Business Practice Manual RESOURCE ADEQUACY Planning Years 2013 and
0 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Manual No. 011 Business Practice Manual RESOURCE ADEQUACY Planning Years 2013 and beyond EXHIBIT ME-2 0 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Disclaimer This document is prepared for informational purposes only to support the development application of enhancements to MISO’s Resource Adequacy construct. Thus the provisions of the Open Access Transmission, Energy and Operating Reserve Markets Tariff (Tariff) of the Midwest Independent Transmission System Operator, Inc. (MISO), Tariff and the services provided under the Tariff. MISO may revise or terminate this document at any time at its discretion without notice. However, every effort will be used by MISO to update this document and communicate key processes, system, and inform its users of changes as soon as practicable. Nevertheless, it is the user’s responsibility to ensure you are using the most recent version posted on the MISO website. In the event of a conflict between this document and the Tariff, the Tariff will control, and nothing in this document shall be interpreted to contradict, amend or supersede the Tariff. This Business Practices Manual (BPM) contains information to augment the filed and accepted Tariff. In all cases the Tariff is the governing document and not the BPMs. Additionally, if not otherwise defined herein, all capitalized terms in this BPM have the meaning as defined in the Tariff. Time Zone In 2006, Central Indiana, where MISO’s offices are located, began observing Daylight Savings Time. However, MISO, its systems, and the Midwest Markets, will continue to do business in Eastern Standard Time year-round. OPS-12 Public Page 2-1 0 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Revision History Doc- Number Reason for Issue Revised by: Effective Date BPM-011-r11 Updated to reflect Module E-1 Tariff C. Clark OCT-01-2012 BPM-011-r10 Updated GVTC language for Hydro and ROR. C. Clark SEP-28-2012 . BPM-011-r9 Annual Review completed and Updated Registration tables and added new section for qualifying PPAs. C. Clark APR-15-2012 BPM-011-r8 MISO Rebranding Changes JUL-19-2011 G. Krebsbach JUN-13-2011 BPM-011-r8 Annual Review and added Dispatchable Intermittent Resource, minor clarifications C. Clark JUN-13-2011 BPM-011-r7 Updated UCAP calculations for plan year 2011/2012, undated Must-offer provisions, updated External Resources cross-border deliverability provisions, updated minor clarifications M. Heraeus / C. Clark Dec-1-2010 BPM-011-r6 Corrected errors and added “Must-Offer” language and Units with Low Service Hours M. Heraeus / C. Clark JUN-1-2010 BPM-011-r5 Corrected errors and inadvertent omissions M. Heraeus MAR-3-2010 BPM-011-r4 Resource Adequacy Improvements Tariff Filing updates. Changed numbering to BPM -011 K. Larson DEC-21-2009 TP-BPM-003-r3 Removed stakeholder comments from section 6.4 that were provided during drafting of TPBPM-003-r2. Amended section 4.4.3.14.4.3.1. T. Hillman JUN-01-2009 TP-BPM-003-r2 Revised to reflect the December 28th, 2007 (ER08-394) filing and subsequent Commission required compliance filings through May 2009 to revise Module E to comprehensively address long-term Resource Adequacy Requirements T. Hillman JUN-01-2009 TP-BPM-003-r1 Revised to reflect Open Access Transmission, Energy and Operating Reserve Markets Tariff for the Midwest ISO, Inc. (Tariff) relating to implementation of the Day-Ahead and RealTime Energy and Ancillary Services Markets and to integrate proposed changes to the J Moser JAN-06-2009 OPS-12 Public Page 2-2 0 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Balancing Authority Agreement. TP-BPM-003 Updated template N/A Section 3.2.1 Determination of Requirements – Non-valid statements were removed. Section 3.2.3 Default Requirements – Minor revisions were made for clarification. Section 3.2.4 Compliance with the Midwest ISO Requirements – Paragraph on after-thefact ECAR “must offer” compliance was removed. Section 4.1 Commercial Pricing Node Load Forecast – Minor revisions were made for clarification. Section 5.2.1 Procedure for Designating a Network Resource for Resource Adequacy Purposes – LD Contracts bullet updated to reflect FERC Order 890. Section 5.2.3 Designating Network Resources External to the Midwest ISO – The second bullet point was revised for clarification. Section 5.3 Determination of Compliance with Network Resource Requirements – This section was deleted. Section 5.4 (5.3) Network Resource Must Offer Requirement – Paragraph on after-thefact ECAR “must offer” compliance was removed. Section 5.5 Financial Transmission Rights – This section was deleted. Section 5.6 (5.4) Updating Network Resource Designations – RE references have been updated to reflect the current NERC Regions. Section 6.1.3 Liquidated Damage and Similar Contracts – Entire section updated to reflect FERC Order 890. Section 6.1.4 Hubbing Transactions – This section was deleted. Section 8 Data Requirements – Entire section updated to reflect FERC order 890 OPS-12 J. Moser Public APR-01-2008 DEC-12-2007 Page 2-3 0 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 TABLE OF CONTENTS 1. Introduction ....................................................................................................................... 2-8 1.1 Purpose of the MISO Business Practices Manuals................................................... 2-8 1.2 Purpose of this Business Manual Document ............................................................ 2-8 1.3 Introduction to RAR Enhancements......................................................................... 2-10 1.4 References .................................................................................................................. 2-10 2. Overview of Resource Adequacy .................................................................................. 2-11 2.1 Establishing Planning Reserve Margin Requirement ............................................. 2-11 2.2 Qualifying Resources ................................................................................................ 2-12 2.3 Resource Adequacy Requirements .......................................................................... 2-12 2.4 Settlements/Performance Requirements ................................................................. 2-13 3. Establishing Planning Reserve Margin Requirement .................................................... 3-1 3.1 Overview ....................................................................................................................... 3-1 3.1.1 Agency Contracts Supporting Resource Adequacy Requirements ........................ 3-2 3.1.2 Validation of Firm Transmission Service for Load ................................................... 3-2 3.2 Coincident Peak Demand Forecast ............................................................................ 3-3 3.2.1 Non-Retail Choice ........................................................................................................ 3-3 3.2.2 Retail Choice ................................................................................................................ 3-3 3.2.3 Review of CPDF ............................................................................................................ 3-5 3.3 Netting of Planning Resources ................................................................................... 3-5 3.4 Full Responsibility Transactions ................................................................................ 3-6 3.5 Planning Reserve Margin ............................................................................................ 3-8 3.5.1 Determination of PRM .................................................................................................. 3-8 OPS-12 Public Page 2-4 0 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 3.5.2 LOLE Analysis .............................................................................................................. 3-9 3.5.3 Loss of Load Expectation (LOLE) Working Group ................................................... 3-9 3.5.4 Probabilistic Analysis LOLE Study .......................................................................... 3-10 3.5.5 Determination of PRM ................................................................................................ 3-12 3.5.6 State authority to set PRM ........................................................................................ 3-13 4. Qualifying and Quantifying Planning Resources ........................................................ 4-15 4.1 Overview ..................................................................................................................... 4-15 4.2 Capacity Resources ................................................................................................... 4-17 4.2.1 Non-Intermittent Generation Resources - Qualification Requirements ............................................................................................................. 4-17 4.2.2 Intermittent Generation and Dispatchable Intermittent Resources– Qualification Requirements ............................................................................................................. 4-21 4.2.3 Use Limited Resources – Qualification Requirements ........................................... 4-28 4.2.4 External Resources - Qualification Requirements .................................................. 4-34 4.2.5 DRR Type I and Type II – Qualification Requirements............................................ 4-43 4.3 Non-Capacity Resources ........................................................................................... 4-47 4.3.1 Load Modifying Resource Obligations and Penalties ............................................ 4-47 4.3.2 BTMG Qualification Requirements ........................................................................... 4-49 4.3.3 Demand Resource – Qualification Requirements ................................................... 4-56 4.3.4 Energy Efficiency Resources .................................................................................... 4-62 4.4 Confirmation and Conversion of UCAP MW ............................................................ 4-72 4.5 ZRC Transactions ...................................................................................................... 4-73 4.5.1 Transfer of ZRCs ........................................................................................................ 4-73 4.5.2 Conversion of ZRCs to UCAP MW ............................................................................ 4-73 OPS-12 Public Page 2-5 0 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 5. Resource Adequacy Requirements ................................................................................ 5-1 5.1 Overview ....................................................................................................................... 5-1 5.2 Local Resource Zones ................................................................................................. 5-1 5.2.1 Change in LRZ Configuration ..................................................................................... 5-3 5.3 Fixed Resource Adequacy Plan (FRAP)..................................................................... 5-6 5.4 Hedges .......................................................................................................................... 5-6 5.4.1 Grandmother Agreements (GMA) ............................................................................... 5-6 5.4.2 Zonal Deliverability Charge and Hedge...................................................................... 5-9 5.5 Planning Resource Auction (PRA) ........................................................................... 5-10 5.5.1 Timing of Auctions. .................................................................................................... 5-10 5.5.2 Amount of Capacity Cleared in Each Auction. ........................................................ 5-10 5.5.3 Conduct of the PRA ................................................................................................... 5-10 5.5.4 Market Monitoring ...................................................................................................... 5-12 5.5.5 Local Reliability Requirement ................................................................................... 5-12 5.5.6 Target Reliability Value .............................................................................................. 5-12 5.5.7 Resource Offers ......................................................................................................... 5-13 5.5.8 Auction Results .......................................................................................................... 5-13 5.6 Retail and Wholesale Load ........................................................................................ 5-15 6. Performance Requirements ............................................................................................. 6-1 6.1 Must Offer Requirement and Monitoring ................................................................... 6-1 6.2 Ongoing Calculation of CONE and Net CONE ........................................................... 6-3 6.3 Replacement Resources ............................................................................................. 6-4 6.4 LMR performance ......................................................................................................... 6-5 6.4.1 BTMG Performance ...................................................................................................... 6-5 OPS-12 Public Page 2-6 0 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 6.4.2 DR Performance ........................................................................................................... 6-6 7. Testing Procedures and Requirements .......................................................................... 7-1 7.1 Generator Real Power Verification Testing Procedures........................................... 7-1 7.2 Midwest Reliability Organization - MRO..................................................................... 7-1 7.3 Reliability First Corporation - RFC ............................................................................. 7-1 7.4 SERC Reliability Corporation – SERC ........................................................................ 7-2 7.5 North American Electric Reliability Corporation – NERC, MOD 24 ......................... 7-2 8. Appendices........................................................................................................................ 8-1 Appendix A – Wind Capacity Credit ....................................................................................... 8-1 Appendix B – Generator Testing and XEFORd details (OMC Codes) ............................... 8-12 Appendix C – Registration of Energy Efficiency Resources ............................................. 8-14 Appendix D – Registration of DRs ....................................................................................... 8-15 Appendix E - BTMG registration .......................................................................................... 8-18 Appendix F – External Resources ........................................................................................ 8-20 Appendix H – Unforced Capacity (UCAP) Calculations for Planning Resources ............ 8-22 Appendix I - XEFORd Calculation ........................................................................................ 8-30 Appendix J – GVTC Testing Requirements ......................................................................... 8-38 Appendix K – Resource Adequacy Timeline ....................................................................... 8-46 OPS-12 Public Page 2-7 0 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 1. Introduction This introduction to the Midwest Independent Transmission System Operator (MISO) Business Practice Manual for Resource Adequacy Enhancements project includes basic information about this and the other MISO BPMs. Section 1.1 of this Introduction provides information about MISO’s Business Practice Manuals (BPMs). Section 1.2 is an introduction to this Business Practice Manual document. Section 1.3 identifies other documents in addition to the BPMs, which can be used by the reader as references when reading this document. Bracketed entries [xx.xx] provide references to MISO’s Tariff which was discussed in the Supply Adequacy Working Group (SAWG) and filed at FERC on July 20, 2011. 1.1 Purpose of the MISO Business Practices Manuals The BPMs developed by MISO provide background information, guidelines, business, and processes established by MISO for the operation and administration of the MISO markets, provisions of transmission reliability services, and compliance with MISO settlements, billing, and accounting requirements. A complete list of MISO BPMs is contained in the List of BPMs and Definitions BPM. This and other BPMs are available for reference through MISO’s website. 1.2 Purpose of this Business Manual Document This Resource Adequacy Business Practice Manual document describes MISO’s and other entities’ roles and responsibilities in terms of the reliability issue of Resource Adequacy, which is ensuring that Load Serving Entities (LSE) serving Load in the MISO Region have sufficient Planning Resources to meet their anticipated peak demand requirements plus an appropriate reserve margin. MISO will update the Resource Adequacy BPM as it relates to the changes made as a result of this project once the design phase of the project has been completed. The Resource Adequacy BPM will conform and comply with MISO’s Energy Markets Tariff (MISO’s EMT), NERC OPS-12 Public Page 2-8 0 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 operating policies, and the applicable Regional Entity (RE) reliability principles, guidelines and standards in order to facilitate administration of efficient Energy Markets. This document benefits readers who want answers to the following questions regarding the proposed Resource Adequacy Requirements (RAR) Enhancements project: How is Resource Adequacy determined? How do the multiple state jurisdictions relate with regard to Resource Adequacy Requirements (RAR)? What are the responsibilities of the different entities with regard to Resource Adequacy? How are specific resources identified and qualified, including contracted resources, for Resource Adequacy purposes? What is a Zonal Resource Credit (ZRC) and how can it be used to comply with RAR? What are the consequences if a Zonal Resource Credit (ZRC) is from a Planning Resource that is determined to be undeliverable to all load within the Region? How are Demand Response Resources (DRR Type I and Type II) incorporated in the Resource Adequacy process? How does an LSE comply with its obligations under the proposed changes to Module E of the Tariff? This document provides the necessary detail to aid a MISO Market Participant’s (MP) understanding of its primary responsibilities and obligations to the reliable operation of MISO’s Balancing Authority Footprint, as a result of the Resource Adequacy Enhancements project. OPS-12 Public Page 2-9 0 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 1.3 Introduction to RAR Enhancements MISO has been working with its stakeholders since March of 2010 to develop enhanced protocols for the provision of Planning Resources to assure reliability in MISO Region. These enhancements include, among other changes: development of Local Resource Zones (LRZs); establishment of zonal requirements; creation of a market mechanism to achieve zonal requirements; respecting states’ rights relating to Resource Adequacy; facilitation of forward capacity procurement requirements; enhancement of forward forecasting accuracy of Load Serving Entities (LSE) Loads; improving Planning Resource qualification procedures; enhancing coordination with retail programs; addressing the Independent Market Monitor’s role with regarding to RAR Enhancements; and improving capacity portability and cross border deliverability. 1.4 References Other reference information related to this document includes: MISO BPMs Draft changes to Open Access Transmission, Energy and Operating Reserve Markets Tariff NERC – Resource and Transmission Adequacy Recommendations, dated June 15, 2004 Federal Energy Regulatory Commission (FERC) Order Nos. 890, Order 890 - A, and Order 890 -B. Module E Capacity Tracking (MECT) tool Users Guide PowerGADS Users Manual OPS-12 Public Page 2-10 0 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 2. Overview of Resource Adequacy Achieving reliability in the bulk electric systems requires, among other things, that the amount of resources exceeds customer demand by an adequate margin. The margins necessary to promote Resource Adequacy need to be assessed on both a near-term operational basis and on a longer-term planning basis. The focus of this BPM is on the longer-term planning margins that are used to provide sufficient resources to reliably serve Load on a forward-looking basis. In the real-time operational environment, only resources dedicated to meet Demand (including resources to meet the Planning Reserve Margin Requirement (PRMR)) have an obligation to be available to meet realtime customer demand and contingencies. Therefore, Planning Reserve Margins (PRMs) must be sufficient to cover: Planned maintenance; Unplanned or forced outages of generating equipment; Deratings in the capability of Generation resources and Demand Response Resources; System effects due to reasonably anticipated variations in weather; and Variations in customer demands or forecast demand uncertainty. 2.1 Establishing Planning Reserve Margin Requirement Each LSEs total obligation will be referred to as the Planning Reserve Margin Requirement (PRMR). Forecasted peak demands are submitted by LSE’s using a 50%-50% forecast (50% probability the forecast will be over, and 50% probability the forecast will be under, the actual peak demand) which will include distribution losses. OPS-12 Public Page 2-11 0 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 2.2 Qualifying Resources The resources used to achieve long-term Resource Adequacy are called Planning Resources, and consist of Capacity Resources, Load Modifying Resources and Energy Efficiency Resources. The relationships and key attributes of the Planning Resource types are as follows: Capacity Resources consist of electrical generating units, stations known as Generation Resources, External Resources (if located outside of MISO), and loads that can be dispatched to reduce demand known as Demand Response Resources that participate in the Energy and Operating Reserves Market and are available during emergencies. Load Modifying Resources (LMR) include Behind-the-Meter Generation (BTMG) and Demand Resources (DR) which are available during all types of emergencies declared by MISO. Capacity Resources are quantified by applying forced outage rates to installed capacity values (ICAP) to calculate an unforced capacity value (UCAP) for the resource. A Market Participant (MP) can use Capacity Resources up to their UCAP values to contribute towards Resource Adequacy. MISO will determine annual unforced capacity (UCAP) values for all qualified Capacity Resources, Load Modifying Resources and for all Energy Efficiency resources for the next Planning Year. 2.3 Resource Adequacy Requirements Planning Resources that clear in the Planning Resource Auction (PRA) or designated in a Fixed Resource Adequacy Plan (FRAP) will be obligated to provide capacity to the relevant Local Resource Zone (LRZ) for the entire Planning Year. LSEs that serve Load during the Planning Year will be obligated to pay for capacity from such Planning Resources pursuant to the relevant Auction Clearing Price (ACP) for the LRZ where the Load that is not included in a FRAP is being served. Resource Adequacy is achieved if an LSE has at least as many Zonal OPS-12 Public Page 2-12 0 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Resource Credits (ZRCs) as its Coincident Peak Forecasted Demand (CPFD) plus its PRM in the LRZ where the LSE is serving the load. In the event that an LSE fails to achieve Resource Adequacy for a Planning Year and chooses to pay the Capacity Deficiency Charge, the charge will be paid to MISO who will distribute it among LSEs in the applicable LRZ that did achieve Resource Adequacy. The Capacity Deficiency Charge is based on 2.7548 times Cost of New Entry (CONE). 2.4 Settlements/Performance Requirements The Planning Resource Reserve Margin Requirement (PRMR) obligations of LSEs will be fixed for the Planning Year and they will be settled based upon the Planning Resource Auction (PRA) clearing price for an LSE’s Load that is not covered by a Fixed Resource Plan (FRAP). Capacity Resources converted to Zonal Resource Credits (ZRCs) will be subject to the must offer requirement which will be based on offering Resources into MISO on a daily basis. Once the Planning Year begins, LSEs and MPs will have the corresponding charges and credits from the Planning Resource Auction as part of their settlements statements for all loads including wholesale and retail load switching OPS-12 Public Page 2-13 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 3. Establishing Planning Reserve Margin Requirement 3.1 Overview The Planning Reserve Margin Requirement (PRMR) is the number of ZRCs required to meet an LSE’s Resource Adequacy Requirements (RAR). This RAR is established to enable LSEs to reliably serve load. Thus, the PRMR ensures that an LSE has enough Planning Resources to reliably serve their load. When the LSE meets this requirement, they have demonstrated that they have acquired enough capacity to meet their Coincident Peak Demand Forecast(CPDF) minus netted Planning Resource, plus transmission losses and the Planning Reserve Margin. The PRMR is expressed in the following equation per Asset Owner and Local Balancing Authority (LBA): 1 % 1 Where: PRMR = Planning Reserve Margin Requirement per Asset Owner and LBA. CPDF= Coincident Peak Forecasted Demand DRNet= Netted Demand Resource EERNet= Netted Energy Efficiency Resource FRP = Full Responsibility Purchase FRS = Full Responsibility Sale TL%LBA= Transmission Loss Percentage of LBA for which the CPDF and/FRS is attributed to PRM = Planning Reserve Margin OPS-12 Public Page 3-1 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 3.1.1 Agency Contracts Supporting Resource Adequacy Requirements An LSE may contract with other entities to comply with RAR. The contracted for entity would perform functions on behalf of the applicable LSE including but not limited to submitting the LSE’s forecasted CPDF or share of CPDF, representation at stakeholder meetings, etc. Each individual LSE is ultimately responsible for conformance with the RAR, even if it enters into a contract with a third party acting on its behalf. Each LSE that contracts with another entity to comply with any part of Module E must notify MISO of the arrangement. The LSE must provide MISO with: the name of the organization representing them; primary and alternate contact information for the individuals representing them; and the scope of responsibilities the contracted for entity will provide. 3.1.2 Validation of Firm Transmission Service for Load Each LSE shall document as described in Module B BPM to MISO that the LSE has obtained sufficient firm Transmission Service for each Month adequate for its Load to be served. Load not served by Network Integrated Transmission Service (NITS) must have Firm Point-to-Point Transmission Service or a firm Grandfathered Agreement, when applicable. However, Demand does not require firm MISO Transmission Service provided that the LSE meets its PRMR using its own Behind-the-Meter Generation (BTMGs) , Demand Resources (DRs) and Energy Efficiency Resources (EERs) and does not use the MISO Transmission System to serve such Demand. OPS-12 Public Page 3-2 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 3.2 Coincident Peak Demand Forecast The Coincident Peak Demand Forecast (CPDF) is demand portion of a PRMR. LSEs or Electric Distribution Companies (EDCs) in retail choice areas must provide MISO with an annual peak forecasted demand coincident with MISO’s annual peak The CPDF shall be based upon considerations including, but not limited to, average historical weather conditions, economic conditions and expected Load changes (addition or subtraction of demand). CPDF should be entered in the MECT based on where the load is physically located and not pseudo-tied. The CPDF is reported differently in non-retail choice and retail choice areas. 3.2.1 Non-Retail Choice LSEs with demand that is not retail choice are required to provide MISO with annual peak forecasted Demand coincident with MISO’s annual peak no later than 11:59 p.m. EST on November 1 prior to the Planning Year. The CPDF must be reported by Asset Owner for each LBA where they serve load. Providing the CPDF by Asset Owner is required by MISO’s settlements process. Reporting by LBA allows MISO to apply the applicable Transmission Losses. Transmission Losses will be reported on the Market Portal by MISO. When S55 data becomes available for June, July, and August, MISO will provide the monthly values. LSEs will include losses on Non-Coincident Peak and Energy for Load forecasts that are reported in the MECT by November 1st prior to the Planning Year. The summer period is from May thru October and the winter period is from November thru April for purposes of providing seasonal forecasts via the MECT. 3.2.2 Retail Choice 3.2.2.1 OPS-12 Electric Distribution Company Public Page 3-3 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 The EDC of a retail choice area is required to provide MISO with an annual peak forecasted Demand coincident with MISO’s annual peak no later than 11:59 p.m. EST on November 1 prior to the Planning Year. EDCs using the preferred default method, must provide both the Transmission Provider and the respective LSEs with each retail customer’s peak load contribution (“PLC”), excluding losses and PRMR, in the EDC’s service territory by no later than 11:59 p.m. December 15th For EDCs that lack data necessary to use the preferred default peak load contribution methodology a daily peak load default methodology will be used. This methodology requires that to EDC must provide both the Transmission Provider and each of the respective LSEs with the LSE’s historic share of the EDC’s Coincident Peak Demand, by no later than 11:59 p.m. December 15th.Load Serving Entity. LSEs with demand in a retail choice are shall work with applicable EDC to confirm and report their share in MWs of the EDC’s service territory’s CPDF no later than 11:59 p.m. January 15th. This share of the EDC’s CPDF must be reported by Asset Owner for each LBA where the LSE serves load. Providing the share of CPDF by Asset Owner is required by MISO’s settlements process. Reporting by LBA allows MISO to apply the applicable Transmission Losses. Transmission Losses will be reported on the Market Portal by MISO. When the S55 data becomes available for June, July, and August, MISO will provide the monthly values. EDCs will include losses on Non-Coincident Peak and Energy for Load forecasts that are reported in the MECT by November 1st prior to the Planning Year. The summer period is from May thru October and the winter period is from November thru April for purposes of providing seasonal forecasts via the MECT. 3.2.2.2 OPS-12 Provider of Last Resort Public Page 3-4 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 The Provider of Last Resort (POLR) will be responsible for meeting any PRMR from demand left unclaimed by LSEs in the EDC service territory. The Transmission Provider will work with POLR and EDC to ensure that POLR will serve any remaining demand that is not allocated to LSE’s. 3.2.3 Review of CPDF Starting November 1st , MISO will review the CPDF and supporting documentation which will conclude on or before March 1st of the following year in order to give all parties adequate time to prepare for the PRA. The review will focus on whether or not the forecast methodology adequately and reasonably forecasts the coincident peak demand of the submitting entity. LSEs will be able to view the status (approved or pending review) of their CPDF in the MECT. MISO will submit forecasts for Market Participants serving Load in the Transmission Provider Region or serving Load on behalf of a Load Serving Entity of other Market Participants that do not submit a CPDF and supporting documentation by the November 1st deadline. 3.3 Netting of Planning Resources The following types of Planning Resources qualify for netting: Demand Resources and Energy Efficiency Resources. LSEs may net their DR or EER from their CPDF prior to MISO applying Transmission Losses and PRM to establish PRMR. For example, if an LSE submits a CPDF of 110MW in the MECT with Demand and/or Energy Efficiency Resources of 10MW then MISO will calculate PRMR based on the reduced CPDF of 100 MW. OPS-12 Public Page 3-5 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 3.4 Full Responsibility Transactions Full responsibility transactions (FRT) are referenced differently depending on which side of the transaction is being addressed. The sale side of and FRT is called a Full Responsibility Sale (FRS) and the purchase side is called a full responsibility purchase (FRP). The FRS results in an increase in demand and FRP results in a decrease in demand. This can be interpreted as the purchaser paying the seller to take on demand and its associated PRMR. The seller of an FRS is contractually obligated to deliver power and energy to the purchaser with the same degree of reliability as provided to the seller’s own native load. With Full Responsibility Service to an LSE within MISO’s Region, sellers are responsible for all of that LSE’s PRMR associated with the sale. FRP and FRS are represented as an adjusted load reduction and addition respectively. LSE (purchaser) may contract with other entities (sellers) to be responsible for capacity payments based upon ACP for all or part of its load delivered to the purchaser, through an FRP/FRS agreement. Each purchaser and seller must agree on which of their transactions are to be reported as an FRP/FRS. If the purchaser and seller cannot agree upon whether a particular transaction is an FRP/FRS agreement, then either party may invoke the dispute resolution procedures in the Tariff. FRP/FRS agreements are treated effectively like a transfer of forecasted Demand and the associated PRMR from one LSE to another. An LSE with an FRP agreement is required to input the forecasted CPF information for the transferred Demand into the MECT. A MP with an FRS agreement is required to meet the RAR obligation derived from the Demand as though it was their load, as described in Section 3. If the seller under an FRP/FRS agreement is not an LSE under the jurisdiction of MISO, then the purchaser under an FRP/FRS agreement will remain responsible for any capacity payments associated with the FRP/FRS agreement. OPS-12 Public Page 3-6 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 If the seller under an FRS/FRP agreement is not an LSE under the jurisdiction of MISO, then the purchaser who is responsible for any RAR deficiencies may coordinate with the nonjurisdictional party to ensure that any RAR obligations associated with transferred Demand are met. Such a purchaser may request that the seller communicate the proper validations and confirmations to the purchaser or confirm validation of RAR obligations in the MECT to the purchaser. Such purchaser also can request that MISO coordinate with the non-jurisdictional party to intermediate the exchange of information from the seller to the purchaser. Such coordination will not relieve the purchaser from responsibilities for any RAR deficiencies associated with the FRP/FRS agreement. The LSE with the FRS is responsible for compliance with LSE requirements. The obligation to serve the load is shifted but the obligation to forecast the Demand remains with the original LSE (purchaser). As shown in the following formula found in Section 69A.2 of the Tariff, the PRM for the LRZ in which the load resides will be applied to the load regardless of which LSE or MP has the reserve obligation. The formula for the LSE’s Planning Reserve Margin obligation is: PRLSE L izones i (1 PRM UCAPi ) Where: PRLSE = Sum of the LSE’s RAR obligation at each LRZ Li = LSE’s CPDF LSE Requirement per each LRZi PRMUCAPi = PRMUCAP for Planning Reserve LRZi and/or state. The purchasing and selling parties will be required to enter and verify the FRP/FRS transaction into the MECT full responsibility transactions screen. The parties must enter an FRP/FRS transaction into the MECT as a full responsibility transaction to enable MISO to track the load OPS-12 Public Page 3-7 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 and capacity obligations shift. This must be done prior to the opening PRA window and the settlement will be between LSEs for all FRP/FRS transactions. The PRMR should not be a negative number as result of the FRT. 3.5 Planning Reserve Margin This section describes changes to the Loss of Load Expectation (LOLE) study process and the process used by MISO to establish the Planning Reserve Margin (PRM) for the MISO Planning Year. A MISO Planning Year runs from June 1 through May 31 of the following year. 3.5.1 Determination of PRM MISO will perform a technical analysis on an annual basis to establish the PRM for the MISO Region based on no internal transmission limitations and will publish the results by November 1st preceding the applicable Planning Year. The PRM analysis shall be consistent with Good Utility Practices and the reliability requirements of the Regional Entities (RE) and applicable states in the MISO Region. The PRM analysis shall consider factors including, but not limited to: the Generator Forced Outage rates of Capacity Resources, Generator Planned Outages, expected performance of Load Modifying Resources (“LMR”) and EE Resources, load forecast uncertainty, and the Transmission System’s import and export capability with external systems. MISO will calculate and publish on its website the estimated PRM for each of the nine subsequent Planning Years, to provide information for long-term resource planning, without establishing any enforceable specific resource planning reserve requirements. OPS-12 Public Page 3-8 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 3.5.2 LOLE Analysis MISO will coordinate with Market Participants to determine the appropriate PRM for the applicable Planning Year. MISO Region based upon the probabilistic analysis of being able to reliably serve MISO’s Coincident Peak Demand for the applicable Planning Year. This probabilistic analysis will utilize a Loss of Load Expectation (LOLE) study which assumes that there are no internal transmission limitations. MISO will annually calculate the PRM such that the LOLE is one (1) day in ten (10) years, or 0.1 day per year. The minimum PRM requirement will be determined using the LOLE analysis by either adding Coincident Peak Demand or removing Planning Resources until a 0.1 day per year solution is reached. MISO will also determine the Local Resource Requirement for each zone consistent with the LOLE to be at 0.1 day per year. The minimum amount of capacity above Coincident Peak Demand required to meet the reliability criteria will be utilized to establish the system wide PRM and the LRR for each zone. 3.5.3 Loss of Load Expectation (LOLE) Working Group MISO has established as an Unforced Capacity requirement based on the LOLE analysis conducted by the LOLE Working Group (LOLEWG) for the purpose of coordinating PRM study work with stakeholders. The duties of the working group are to help guide MISO in implementing the study methods outlined in the following sections. The LOLEWG will work with MISO staff to perform the LOLE analysis that calculates the PRM requirements for each LSE within MISO. This analysis will conform to the Electric Reliability Organization (ERO) standards, including those established by applicable REs for reliability and resource adequacy. The LOLEWG will also review and provide recommendations to MISO on the methodology and input assumptions to be used in performing the LOLE analysis, as well as reviewing the results of the LOLE analysis and related sensitivity cases. The LOLEWG will use this information as the basis for providing recommendations on the PRM and LRR’s to MISO. OPS-12 Public Page 3-9 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 3.5.4 Probabilistic Analysis LOLE Study The probabilistic study will use the General Electric's Multi-Area Reliability Simulation (GE MARS) software application. Primary inputs are the generation data submitted to MISO through the GADS tool and forecasted Demands provided as described in section 3 of this BPM. Aside from the generation outage performance that has statistical parameters, the GE MARS model requires information to model sub-areas or zones in the Energy and Operating Reserves market and also to model transmission capability among such zones. LSEs are obligated to report GADS data for Generation Resources and External Resources through the MISO Market Portal. The specific XEFORd outage parameter is developed from this data and together with the capacity of each resource are the key generator inputs to the GE MARS application. The XEFORd and EFORd metrics are more fully described below. The zones to be modeled in the MARS application are discussed in Section 5.2 Local Resource Zones Although the compliance rating for individual generators will be based on the XEFORd metric, the LOLE study also will account for additional system wide outages beyond the outage causes captured in the XEFORd metric. The XEFORd metric focuses on the manageable performance differences among individual generators. There are also outages, however, that are caused by Force Majeure conditions that are outside of management control and can result in Generation Resources being unavailable, for example, due to weather conditions. The distinction is tracked with two specific forced outage rate metrics, EFORd and XEFORd. The two terms are defined as: Equivalent demand Forced Outage Rate (EFORd): A measure of the probability that a generating unit will not be available due to forced outages or forced deratings when there is demand on the unit to generate. XEFORd: Same meaning as EFORd, but calculated by excluding causes of outages that are Outside Management Control (OMC). For example, losses of transmission outlet lines are considered as OMC relative to a unit’s operation. OPS-12 Public Page 3-10 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Currently, the MISO study utilizes 27 cause codes in its OMC set of outages The 27 OMC Codes approved by stakeholders for use in the MISO LOLE study are listed in Appendix B of this BPM. The accommodation of Force Majeure outage causes by using the EFORd metric as the input data to the GE MARS application is normal; however, a sensitivity run with the XEFORd metric will normally be done to examine the impact of the Force Majeure event. Similarly, the allowance for carrying contingency reserves may be used as an input to the GE MARS application to study the impact of covering contingency reserve or any other component of operating reserves that may be desirable to quantify. The formula for an LSE’s Planning Reserve Margin Requirement obligation is as follows: PRMRLSE = [L1 x (1+PRMUCAP1)] + [L2 x (1+PRMUCAP2)] . . . + [Ln-1 x (1+PRMUCAPn-1)] + [Ln x (1+PRMUCAPn)] Where: PRMR can be satisfied by the use of Capacity Resources and/or LMR. L1 = LSE’s Forecast LSE Requirement in Zone 1 (after subtracting any applicable Demand Resources) L2 = LSE’s Forecast LSE Requirement in Zone 2 (after subtracting any applicable Demand Resources). . . etc. PRMUCAP1 = PRMUCAP for Zone 1 PRMUCAP2 = PRM UCAP for Zone 2 . . . etc. For all Zones: PRMUCAPn = the greater of PRMUCAPmiso or (LCRZn / LoadZn - 1) ZLZn = Total Load in Zone n LCRZn = Local Clearing Requirement for Zone n OPS-12 Public Page 3-11 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 3.5.5 Determination of PRM MISO shall perform a technical analysis on an annual basis to establish the PRM for the MISO Region and will publish the results by November 1st preceding the applicable Planning Year. The analysis includes calculating the driving parameters for determining the Local Clearing Requirement (LCR) in each Zone. Those drivers are Local Reliability Requirement (LRR), the Capacity Import Limit (CIL) and the Capacity Export Limit (CEL). Details of the method to calculate the CIL and CEL are discussed in Section 5.2.1.2. Because Capacity Resources are being credited at their UCAP value the reserve requirements must also use a UCAP rating to be equitable. The PRM that is calculated in the LOLE study software is determined on an ICAP basis. This PRMRICAP value is the sum of the ICAP ratings of the resources utilized in the simulation to achieve the reliability criteria. Similarly, the sum of the UCAP ratings of these same resourced utilized in the simulation to achieve the reliability criteria is the total UCAP rated MW needed, or the PRMPUCAP. The MISO system average XEFORd=(1 + PRMRUCAP / PRMRICAP). The PRMR is set to meet Forecast LSE Requirements multiplied by one (1) plus the applicable PRM established either by MISO, or by the state having jurisdiction over the applicable LSE. OPS-12 Public Page 3-12 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Previous LOLE studies were based on the LSE forecasts that were Non-coincident with the MISO system peak. Based on LSE forecast at time of MISO peak under the new construct starting in PY 2013-2014, the Planning Reserve Margins that would have been for past Planning Years are shown in the table below: Load Based1 (UCAP) MISO System wide Forced Outage Rate (XEFORd) Coincident Load Based (ICAP) 7.89 % 6.51% 15.40% 7.74 % 6.64% 15.40% 8.76 % 7.36% 16.10% 8.80% 6.77% 16.7% Coincident Planning Year 1 (2009-2010) Total PRM Planning Year 2 (2010-2011) Total PRM Planning Year 3 (2011-2012) Total PRM Planning Year (2012-2013) Total PRM 1 Applicable to Forecast LSE Requirement at time of MISO peak See MISO’s website for current and previous LOLE studies. 3.5.6 State authority to set PRM The only entity other than MISO that may establish a PRM is a state regulatory body regarding those regulated entities under their jurisdiction. If a state regulatory body establishes a minimum PRM for the LSEs under their jurisdiction, then that state-set PRM would be adopted by MISO for affected LSEs in such state. If a state regulatory body establishes a PRM that is higher or than the MISO established PRM, the affected LSEs must meet the state set PRM. Similarly, if a state utility commission establishes a PRM that is lower than the MISO established OPS-12 Public Page 3-13 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 PRM, then the state set PRM will be applied to the LSE’s Coincident Peak Demand to determine an LSE’s capacity obligations. Other entities, such as reserve sharing groups or NERC Regional Entities, do not have the authority to establish a PRM under Module E. MISO will translate any state-set PRM into the same terms as MISO’s PRM (e.g. utilizing a UCAP basis) to facilitate comparison and compliance with PRM Requirements (PRMR). OPS-12 Public Page 3-14 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 4. Qualifying and Quantifying Planning Resources 4.1 Overview MISO has worked with its stakeholders in order to attempt to build consensus regarding the processes required to qualify Planning Resources consistent with the Resource Adequacy Requirement (RAR) Enhancements. MISO made a FERC filing in July of 2011 to implement the processes required to qualify Planning Resources consistent with the RAR Enhancements, to become effective for the 2013-2014 Planning Year. All Planning Resources that qualify will have a UCAP value determined by MISO. The benefits of UCAP include: fair recognition of the contribution each unit provides towards Resource Adequacy market signals that will promote generating unit availability performance; and in turn, the improved System Availability will promote improved regional Resource Adequacy supporting bilateral trades by recognizing the UCAP value of each resource, while importantly shifting the resource performance risk to owners of Planning Resources, where such risk more properly belongs Generation Resources and Demand Response Resources backed by behind the meter generation in the Commercial Model that have met all requirements to supply capacity in the MISO Resource Adequacy construct will have UCAP MWs calculated based on data submitted by the Asset Owner, as described in the Appendix H of this document. BTMG, DR, Energy Efficiency Resources, and External Resources must follow the registration procedures documented elsewhere in this document to be eligible to supply capacity in the MISO Resource Adequacy construct (mostly in the Appendices C thru F including Section 4.2.4 for External Resources). Generation Resources and Demand Response Resources backed by behind the OPS-12 Public Page 4-15 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 meter generation that do not have historical performance data will have their UCAP calculated for them after they are listed in MISO's Commercial Model (which is updated quarterly), provided that the Resource meets the Capacity Resource Module E requirements. The following Table outlines the relationship and key attributes of the Planning Resource types. Capacity Verification 1 Must offer 1 GADS Data Entry Must Respond to Emergency Operating Procedures Planning Resource Capacity Resource Load Modifying Resource Generation Demand Response and Resources External X X X X X X X X X Demand Energy BTMG Resource Efficiency X X X X X X X X 1 - Includes Intermittent Capacity with must offer requirement met as price taker in the DA Market. 2 - BTMG greater than 10 MW must supply GADS OPS-12 Public Page 4-16 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 4.2 Capacity Resources 4.2.1 Non-Intermittent Generation Resources - Qualification Requirements Generation Resources may qualify as Capacity Resources provided that: They are registered with MISO as documented in the Market Registration BPM. Generation Resources must be deliverable to Load within MISO’s Region. The deliverability of Generation Resources to Network Load within MISO’s Region shall be determined by System Impact Studies pursuant to the Tariff that are conducted by MISO, which consider, among other factors, the deliverability of aggregate resources of Network Customers to the aggregate of Network Load or by demonstrating firm transmission service is in place between the Generation Resource and Network Load. The Deliverability Test Results are provided on MISO’s public website at the following location: Document > Planning Information > Generator Interconnection Planning > Generator > Generation Deliverability Tests > Test Results > Deliverability Test Results. Network Contract Numbers cannot be used, the Transmission Service Request must either be Firm Point to Point or Firm Network Designated Monthly transmission service requests may be used as long as they cover the entire Planning Year in aggregate and are provided in the MECT. Internal purchase power agreements (PPAs) will not be qualified by MISO. Generation Resources must register with MISO as documented in the Market Registration BPM. OPS-12 Public Page 4-17 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Generation Resources greater than or equal to 10 MW, based on Generation Verification Tested Capacity (GVTC), must submit generator availability data (including, but not limited to, NERC GADS) into a database through the Market Portal. The definition of Generation Resources does not include Intermittent Resources or Intermittent Generation and Dispatchable Intermittent Resources. Generation Resources less than 10 MW based upon GVTC that begin reporting generator availability data must continue to report such information. Generation Resources that are new to MISO must submit GVTC and if greater than or equal to 10 MW based on GVTC, then the Resource must submit GADS prior to being approved as a Capacity Resource. The XEFORd for new Generation Resources in service less than twelve full calendar months will be the class average for the resource type. A Generation Resource will use the class average value until 12 consecutive months of data is available and a new Planning Year has occurred. Generation Resources are not in an Attachment Y status (retired/mothballed/suspended) and operational when being used as a Planning Resource for any Planning Year. Generation Resources must demonstrate capability on an annual basis as described below. o MISO has developed generator testing standards o All Generation Resources being used as a Planning Resource are required to perform a real power test according to MISO’s Generator Test Requirements and submit the GVTC data to MISO’s PowerGADS no later than October 31st in order to qualify as a Planning Resource. The test shall be performed between September 1st and August 31 of the prior OPS-12 Public Page 4-18 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Planning Year and corrected to the average temperature of the date and times of MISO’s coincident Summer peak, measured at or near the Generation Resource’s location, for the last 5 years, or provide past operational data that meets these requirements to determine its GVTC and submit its GVTC data to MISO’s PowerGADS. When to Perform and Submit a Generation Verification Test Capacity (GVTC) Generation Resources, External Resources, Demand Response Resources backed by behind the meter generation, or Behind the Meter Generation (BTMG) that qualified as Planning Resources for the current Planning Year shall submit their GVTC no later than October 31st in order to qualify as a Planning Resource for the upcoming Planning Year. The real power test shall be performed or past operational data shall be between September 1st and August 31st prior to the upcoming Planning Year. A real power test is required to demonstrate a modification that increases the rated capacity of a unit and a revised GVTC should be submitted to MISO no later than March 1st prior to the Planning Year. A real power test is required when returning from a “mothballed” state, and the GVTC should be submitted to MISO. A real power test is required when any existing or new unit returns to MISO after an absence (including but not limited to, catastrophic events, or not qualified as a Planning Resource under Module E) or being qualified as a Planning Resource for the first time. The GVTC tests result should be submitted to MISO. OPS-12 Public Page 4-19 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 The GVTC for a new Non-Intermittent Generation resource is due by March 1st prior to the Planning Year. See Appendix J of this BPM for links to MISO’s GVTC Manual and processes. Reporting o Reporting is accomplished through MISO’s PowerGADS reporting system as described in Net Capability Verification Test User Manual, which is located on MISO’s website under Documents Planning > Resource Adequacy> Documents> GADS Information Link (Module E) > PowerGADS Documentation> Generator Testing Documents. 4.2.1.1 Non-Intermittent Generation Resources – UCAP Determination The UCAP value for a Generation Resource is based on an evaluation of the type and volume of interconnection service, GVTC value, and XEFORd value of such Generation Resource as described in Appendix H-I of the RAR BPM. The UCAP methodology is implemented to address the fact that not all Generation Resources contribute equally to Resource Adequacy. By adjusting the capacity rating of a unit based on its XEFORd, UCAP provides a means to recognize the relative contribution that each resource makes towards Resource Adequacy. When the PRM requirement is similarly adjusted by the weighted average XEFORd of all the pooled resources, the generating units with better than average availability will reflect higher values than units with below average availability. UCAP MW options for units with derates prior to the GVTC test date is further explained in Appendix J.4 of the RAR BPM. OPS-12 Public Page 4-20 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Non-Intermittent Generation Resource – Must-Offer As described in detail in Section 6.1 of this BPM, an MP that converts a Generation Resource’s UCAP MW into ZRCs must submit the full operable capacity of the Resource, but not less than the ICAP value of what was converted to ZRCs, and make an Offer into the Day-Ahead Energy, and each pre Day-Ahead, and the first post Day-Ahead Reliability Assessment Commitment (RAC), for every hour of every day, except to the extent that the Generation Resource is unavailable due to a full or partial forced scheduled outage. Outages and derates must be reported in the MISO Outage Scheduler (CROW). Compliance with “must offer” requirements will be evaluated by MISO on a non-discriminatory basis. MISO will analyze the compliance with must offers in both the Day-Ahead and RAC by taking into account information provided by the MISO Outage Scheduler (CROW) and operational limitations, including, but not limited to, those related to fuel limited, energy output limited or Intermittent Generation and Dispatchable Intermittent Resources. 4.2.2 Intermittent Generation and Dispatchable Intermittent Resources– Qualification Requirements Intermittent Generation and Dispatchable Intermittent Resources may qualify as Capacity Resources provided that: They are registered with MISO as documented in the Market Registration BPM. Intermittent Generation and Dispatchable Intermittent Resources must be deliverable to Load within MISO’s Region. The deliverability of Intermittent Generation and Dispatchable Intermittent Resources to Network Load within MISO’s Region shall be determined by System Impact Studies pursuant to the Tariff as conducted by MISO, which shall consider, among other factors, the OPS-12 Public Page 4-21 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 deliverability of aggregate resources of Network Customers to the aggregate of Network Load, or by demonstrating from transmission service that is in place between the Generation Resource and Network Load. The Deliverability Test Results are provided on MISO’s public website at the following location: Documents > Planning Information > Generator Interconnection Planning > Generator > Generation Deliverability Tests > Test Results > Deliverability Test Results. Workbook. Network Contract Numbers cannot be used, the Transmission Service Request must either be Firm Point to Point or Firm Network Designated Monthly transmission service requests may be used as long as they cover the entire Planning Year in aggregate and are provided in the MECT. Internal purchase power agreements (PPAs) will not be qualified by MISO. Intermittent Generation and Dispatchable Intermittent Resources are not in an Attachment Y status (retired/mothballed/suspended) and are operational when being used as a Planning Resources for a Planning Year. Intermittent Generation and Dispatchable Intermittent Resources that are not powered by wind must supply MISO with the most recent consecutive three years of hourly net output (in MW) for hours 1500 – 1700 EST from June, July and August. For new resources, or resources on qualified extended outage where data does not exist for some or all of the previous 36 historical months, a minimum of 30 consecutive days’ worth of historical data during June, July or August for the hours of 1500 - 1700 EST must be provided. Intermittent Generation and Dispatchable Intermittent Resources not powered by wind which do not have a minimum of 30 consecutive days of historical data from June, July, or August for the hours of 1500-1700 EST prior to the Planning Year, OPS-12 Public Page 4-22 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 will be granted a class average EFORd based on their unit type and size. In the event that a class average EFORd does not exist, the MP shall provide at least 30 consecutive days of operating data for the resource prior to participating in any PRAs. 4.2.2.1 Intermittent Resource - Generation - UCAP Determination The Unforced Capacity for a Capacity Resource that is Intermittent Generation and Dispatchable Intermittent Resources will be determined by MISO based on historical performance, availability, and type and volume of interconnection service. Intermittent Generation and Dispatchable Intermittent Resources is not required to report generator availability data (GADs) and will be assigned a XEFORd of zero. Intermittent Generation and Dispatchable Intermittent Resources that are powered solely by wind will have their annual UCAP determined based on interconnection service volumes and a Region wide capacity credit as a percentage of the Maximum Output as modeled in the effective Commercial Model at the time of calculating UCAP values (see table below for annual Intermittent Capacity Credit). Intermittent Resources that are powered solely by wind are not required to report GADS data and will be assigned an XEFORd of zero. 4.2.2.2 Intermittent Generation and Dispatchable Intermittent Resources – Wind Capacity Credit MISO uses historical wind availability information to calculate Effective Load Carry Capacity (ELCC) to determine a wind capacity credit. MISO’s Wind Capacity Credit Report by the LOLEWG reports the wind capacity results for each Planning Year. Appendix A of this BPM explains the methodology that is used annually. See MISO’s website for previous LOLE studies, and starting 2013 the wind capacity is in a standalone report from the LOLE report which sets the Planning Reserve Margin (PRM). OPS-12 Public Page 4-23 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Wind Capacity Credit Calculation; MISO calculates specific wind capacity credit for each wind farm and applies it to its registered maximum capability in the Commercial Model or its registered Capacity through the LMR or External Resource registration process. The wind capacity credit MW for the MISO system is allocated to each wind farm based on its capacity value at each of MISO’s top 8 highest coincident peaks that occurred during the Summer. The Wind Capacity Credit Report includes analysis and results. This calculation is done on a CPNode basis for wind farms that are registered in MISO’s Commercial Model, and on a wind farm basis as submitted through the Planning Resource registration process for External Resources and Behind the Meter Generation. A wind farm that does not have any commercial operation history will receive a wind capacity credit equivalent to the system wide wind capacity credit from the ELCC study, for their initial Planning Year, and thereafter metered data is will be used in order to calculate its future wind farm specific wind capacity credit, if no metered data is available then the wind farm with receive a capacity credit of 0%. Planning Year Total System Wind Capacity Credit 2012-2013 14.7% 4.2.2.3 Intermittent Generation and Dispatchable Intermittent Resources – Non-wind For Run of River Hydro, the median hourly integrated net output from the most recent three (3) years up to the most recent fifteen (15) years for hours ending 1500-1700 EST for all days of OPS-12 Public Page 4-24 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 the Summer (June, July, August) shall be used. If 15 years of historic data is not available for this period when the 15 year time period is chosen, or is no longer relevant due to environmental, operational, regulatory or other restrictions, all available relevant data shall be used and accumulated until the 15 year requirement is met. Once the number of years and methodology is chosen and submitted as GVTC requirements, the same number of years must be submitted in future GVTC data collection. All other Intermittent Generation and Dispatchable Intermittent Resources will have their annual UCAP value determined based on the 3 year historical average output of the resource for hours 1500-1700 EST for the most recent Summer months (June, July, and August). Market Participants with non-wind powered Intermittent Generation and Dispatchable Intermittent Resources will need to supply this historical data to MISO by October 31 of each year in order to have their UCAP value determined. Non-wind powered Intermittent Generation and Dispatchable Intermittent Resources that are new, upgraded or returning from extended outages shall submit all operating data for June, July, or August with a minimum of 30 consecutive days, in order to have their new or upgraded capacity registered with MISO. An example of a qualified extended outage is a resource that does not have a transmission path due to a planned or forced transmission outage. Resources that experience changing characteristics during the historical period due to changing nameplate capability will have the historical data adjusted by a ratio of the current nameplate rating divided by the nameplate rating in effect at the time the data was collected. For resources that experience partial outages not related to the supply of fuel (e.g. water conditions), regular maintenance, or shutdowns due to safety concerns (e.g. high water), the historical data may be prorated upward to reflect the expected value as if all units had been on line. For units that experience reduced output due to reasons outside of management control (e.g. flood conditions) data from these periods may be excluded from the calculation of UCAP. The annual UCAP will be the three year average output value after the adjustments as described above have been made. OPS-12 Public Page 4-25 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 UCAP MW options for units with derates prior to the GVTC test date is further explained in Appendix J.4 of the RAR BPM. An increase in unit capability for Intermittent Generation and Dispatchable Intermittent Resources that are solely powered by wind after the annual UCAP values have been established will require written notification from the Market Participant to a member of the Resource Adequacy Team in order to update the values. 4.2.2.4 Intermittent Resource Generation and Dispatchable Intermittent Resources – Must Offer As described in detail in Section 6.1 of this BPM, an MP that converts an Intermittent Resource’s UCAP MW into ZRCs must submit the full operable capacity of the Resource, but not less than the ICAP value of what was converted to ZRCs, and make an Offer into the DayAhead Energy and each pre Day-Ahead and the first post Day-Ahead Reliability Assessment Commitment (RAC) for every hour of every day, except to the extent that the Intermittent Resource is unavailable due to a full or partial scheduled outage The must offer requirement applies to the Installed Capacity of the Intermittent Generation and Dispatchable Intermittent Resources, and not to the UCAP rating. Installed Capacity refers to the amount of ZRCs divided by (1 – XEFORd) of the Capacity Resource. DA Reliability Forecasts submissions for Intermittent Generation and Dispatchable Intermittent Resources received by DA close and Forward Reliability Assessment Commitment (FRAC) close of the DA Market close, and FRAC close, will be used to monitor for compliance with the must-offer requirement when the unit’s availability is due to non-mechanical and/or nonmaintenance reasons. The must-offer monitoring process for Intermittent Generation and Dispatchable Intermittent Resources that submit a DA Reliability Forecast by DA Market close and FRAC close will check that the offers submitted are greater than or equal to the volumes submitted via the DA Reliability Forecast. The same Intermittent Forecast data file used in Day Ahead Must-Offer compliance shall be utilized in FRAC if no further update is provided. If a DA OPS-12 Public Page 4-26 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Reliability Forecast is submitted on time and in the correct format, it replaces the Installed Capacity as the Must-Offer requirement that is listed in the MECT under “Resource Adequacy Requirement”. Format instructions are located at www.misoenergy.org under Related Documents>Market Procedures Documents and Technical Manuals>Registration>Reference Documents> Resource Forecast Data Submittal for Reliability Guide. https://www.misoenergy.org/StakeholderCenter/MarketParticipants/Pages/MarketParticipants.aspx A header row should be included at the beginning of the file in the format Resource, Day, Hour Ending (HE), and MW. The must offer monitoring process for Intermittent Generation and Dispatchable Intermittent Resources that do not to provide the DA Reliability Forecast by the DA Market close and the FRAC close, will be based on offers submitted and outages or derates submitted in MISO’s Outage Scheduler (CROW). The must-offer process will be based on the daily and hourly offers submitted by the Asset Owner. Additionally, maintenance and mechanical outages to Intermittent Forecasts will be based on the forecasts only; and the thresholds established will not Generation and Dispatchable Intermittent Resources should be used as indicated in Section 6.1.the MISO Outage Scheduler (CROW). Additionally, maintenance and mechanical outages to Intermittent Resources should be entered in CROW. For purposes of calculating the must-offer requirement for Intermittent Generation and Dispatchable Intermittent Resources powered by wind, an XEFORd of one minus the footprint wide capacity credit will be used. For non-wind Intermittent Generation and Dispatchable Intermittent Resources, the XEFORd will be set equal to the UCAP divided by the ICAP, where the ICAP shall be the maximum value registered in the Commercial Model. For non-wind Intermittent Resource not modeled in the Commercial Model, the ICAP will be the name plate capacity value as provided by the MP.MECT. OPS-12 Public Page 4-27 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 4.2.3 Use Limited Resources – Qualification Requirements Use Limited Resources are defined as Generation Resources or External Resource(s), that due to design considerations, environmental restrictions on operations, cyclical requirements (such as the need to recharge or refill), or for other non-economic reasons, are unable to operate continuously on a daily basis, but are able to operate for a minimum set of consecutive operating Hours. A Capacity Resource may be defined as a Use Limited Resource if it: is capable of providing the Energy equivalent of its claimed Capacity for a minimum of at o least four (4) continuous hours each day across MISO’s peak; o submits GADS Data to MISO; o notifies MISO of any outage (including partial outages) and the expected return date from the outage; o demonstrates capability and submit the results to MISO; and o identifies the resource as use limited when registering the asset, subject to MISO approval. MISO will review the conditions of the asset or PPA to determine if the resource qualifies as a Use Limited Resource. Use Limited Resources may qualify as Capacity Resource provided that: o The Use Limited Resources must be deliverable to Load within MISO’s Region. The deliverability of Use Limited Resources to Network Load within MISO’s Region shall be determined by System Impact Studies pursuant to the Tariff as conducted by MISO, which will consider, among other factors, the deliverability of aggregate resources of Network Customers to the aggregate of Network Load. The Deliverability Test Results are provided on MISO’s public website at the following location: Top > Planning Information > OPS-12 Public Page 4-28 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Generator Interconnection Planning > Generator> Generation Deliverability Tests > Test Results > Deliverability Test Results workbook. Use Limited Resources must register with MISO as documented in the Market Registration BPM. Network Contract Numbers cannot be used, the Transmission Service Request must either be Firm Point to Point or Firm Network Designated Monthly transmission service requests may be used as long as they cover the entire Planning Year in aggregate and are provided in the MECT. o Internal purchase power agreements (PPAs) will not be qualified by MISO. o Use Limited Resources (that are not Intermittent Generation and Dispatchable Intermittent Resources) must submit generator availability data (including, but not limited to, NERC GADS) into a database through the Market Portal. o New Use Limited Resources must submit GVTC and if it is greater than or equal to 10 MW based on GVTC, then it must submit GADS prior to being approved as a Capacity Resource. o Use Limited Resources less than 10 MW based upon GVTC that begin reporting generator availability data to MISO must continue to report such data. o The XEFORd for new Use Limited Resources in service less than twelve full calendar months will be the class average for the resource type. A Use Limited Resource will use the class average value until 12 consecutive months of data is available and a new Planning Year has occurred. o MISO will qualify a resource classified as a Diversity Contract provided the resource meets all of the requirements as an External Resource and the Diversity Contract OPS-12 Public Page 4-29 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 includes a one MW of summer for one MW of non-summer capacity swap, in order to participate in the Planning Resource Auction (PRA). o Use limited Resources that are not in an Attachment Y status (retired/mothballed/suspended) and are operational when being used as a Planning Resource for a Planning Year. o Use Limited Resources must demonstrate capability on an annual basis. o Planning Year Testing: MISO has developed generator-testing standards All Use Limited Resources being used as a Planning Resource are required to perform a real power test according to MISO’s Generator Test Requirements and submit the GVTC data to PowerGADS no later than October 31st in order to qualify as a Planning Resource. The test shall be performed between September 1 and August 31 of the prior Planning Year and shall be corrected to the average temperature of the date and times of MISO’s coincident Summer peak, measured at or near the generator’s location, for the last 5 years, or the operator shall provide past operational data that meets these requirements to determine its and submit its GVTC data to MISO’s PowerGADS When to Perform and Submit a Generation Verification Test Capacity (GVTC) Generation Resources, External Resources, Demand Response Resources backed by behind the meter generation, or BTMG that qualified as Planning Resources for the current Planning Year, shall submit their GVTC no later than October 31st of the prior Planning Year in order to qualify as a Planning Resource for the upcoming Planning Year. The real power test shall be performed or past operational data shall be used which is between September 1st and August 31st prior to the upcoming Planning Year. OPS-12 Public Page 4-30 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 A real power test is required to demonstrate a modification that increases the rated capacity of a unit, and then the revised GVTC data should be submitted to MISO. A real power test is required when returning from a “mothballed” state, and the owner of the unit must submit GVTC data to MISO. A real power test is required when any existing or new unit returns to MISO after an absence (including but not limited to, catastrophic events, or if not qualified as a Planning Resource under Module E), or after being qualified as a Planning Resource for the first time. The GVTC for a new Use Limited Resource that is an External Resource is due before a Market Participant registers its new Use Limited Resource in the MECT, and the GVTC data must be submitted by March 1st prior to the Planning Year. For new Use Limited Resources internal to MISO, the GVTC data should be submitted no later than March 1st prior to the Planning Year. See Appendix J of this BPM for links to MISO’s GVTC Manual and processes. Reporting Reporting is accomplished through MISO’s PowerGADS reporting system, as described in MISO’s PowerGADS User’s Net Capability Verification Test User Manual. The PowerGADS users Manual is located on MISO’s website, at www.misoenergy.org and then under Documents→ Planning Information→> Resource Adequacy> Documents> GADS Information→ Link Planning > Resource Adequacy (Module E) > PowerGADS Documentation→ PowerGADS User’s Manual.> Generator Testing Documents. OPS-12 Public Page 4-31 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Beginning with Planning Year 3, the Asset Owner must submit its test results no later than October 31 of each year. 4.2.3.1 Use Limited Resources – UCAP Determination The UCAP value for a Use Limited Resource is based on an evaluation of the type and volume of interconnection service, GVTC value and XEFORd value of such Use Limited Resource as described in Appendix H of the RA BPM. The UCAP methodology is implemented to address the fact that not all Use Limited Resources contribute equally to Resource Adequacy. By adjusting the capacity rating of a unit, based on its XEFORd, UCAP provides a means to recognize the relative contribution that each Use Limited Resource makes towards Resource Adequacy. The PRMUCAP requirement is similarly adjusted by the weighted average XEFORd of all the pooled resources; the generating units with better than average availability will reflect higher value than units with below average availability. UCAP MW options for units with derates prior to the GVTC test date is further explained in Appendix J.4 of the RAR BPM. 4.2.3.2 Use Limited Resources Must-Offer Requirement As described in detail in Section 6.1 of this BPM, an MP that converts a Generation Resource’s UCAP MW into ZRCs must submit the full operable capacity of the Resource, but not less than the ICAP value of what was converted to ZRCs, and make an Offer into the Day-Ahead Energy and each pre Day-Ahead and the first post Day-Ahead Reliability Assessment Commitment OPS-12 Public Page 4-32 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 (RAC) for every hour of every day, except to the extent that the Generation Resource is unavailable due to a full or partial forced scheduled outage. A Use Limited Resource must-offer or Self-schedule into the Day-Ahead Market for at least four (4) continuous hours daily across MISO’s peak in such a way as to enable MISO to have an opportunity to schedule the Resource for the period in which the Use Limited Resource will not be recharging or replacing depleted resources. MISO’s peak period will be based on the forecast published one day prior to the operating day including 2 hours prior to the beginning of the peak hour through the end of the hour following the peak hour as specified in the Market Report provided at the link provided below. https://www.misoenergy.org/Library/MarketReports/Pages/MarketReports.aspx Under report name, type “look ahead” in the box. A list of summary reports will appear and you can click on corresponding date. An MP with a Use Limited Resource is required to submit a must-offer or Self-Schedule for at least the number of minimum capacity hours optimized to match the expected peak load in the Region. Once the Resource has provided at least four continuous hours of Energy, all Outages and derates for Use Limited Resources need to be reflected in MISO’s Outage Scheduler (CROW). Thresholds for Use Limited Resources will only be applied during the four continuous hours across MISO’s peak. MISO will not call upon a Use Limited Resource during its recharge hours, except in the case of an Emergency, in accordance with the must-offer provisions in section 4.2.3.2. OPS-12 Public Page 4-33 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 4.2.4 External Resources - Qualification Requirements External Resources can qualify as Capacity Resources as follows: MPs may register an External Resource by providing the information listed below to MISO to qualify such resources as Capacity Resources by registering such resources through the MECT for the upcoming Planning Year. An MP that owns External Resources or contracts for an External Resource via a power purchase agreement (PPA) may also register its External Resources. The MP shall notify MISO if the External Resource being registered is an Intermittent Generation or Use Limited Resource. External Resources that are also Intermittent Generation must meet all requirements in section 4.2.2. External Resources that are also Use Limited Resources must meet all requirements in section 4.2.3 and be approved by a member of the Resource Adequacy team. An MP will submit the completed applicable registration form for existing resources via the MECT by February 1st prior to the Planning Year. New External Resource registrations or existing registrations with increased capacity are to be completed in the MECT by March 1st prior to the Planning Year. The registration form will require the MP to certify that the registration information is accurate, complete, and that the qualified MWs from the External Resources are not being registered by another party. MISO will notify the MP within 15 days after a completed registration form is received regarding accreditation of the External Resource. MISO will review the External Resource registration form for completeness and accuracy, and will notify the MP when it is determined whether or not the External Resource has been accredited, or whether there are any deficiencies. If the External Resource qualifies, it will be given a unique name for tracking purposes. MISO will coordinate with appropriate neighboring entities (RTOs, LBAs, etc.) to ensure that External Resources are not being utilized for capacity purposes by such entities. The reason for this coordination effort is to eliminate double counting of capacity across seams. OPS-12 Public Page 4-34 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 The following information will be required in order to register an External Resource and MPs that register External Resources may receive eligible UCAP provided that the MP: demonstrates that there is firm Transmission Service from the External Resource to the border of MISO’s Region, and that; firm Transmission Service has been obtained to deliver at least the ICAP amount of the Capacity Resource seeking to be qualified on the Transmission System from the External Resource(s) to the CPNode. The CPNode will be interpreted as the Local Balancing Authority (LBA) that MISO’s OASIS reservation sinks in for Network Customers, or ; o The External Resource has Network Resource Interconnection Service under Attachment X, and can demonstrate use of the Network Resource Interconnection Service by having firm Transmission Service to Load. Network Contract Numbers cannot be used, the Transmission Service Request must either be Firm Point to Point or Firm Network Designated Monthly transmission service requests may be used as long as they cover the entire Planning Year in aggregate and are provided in the MECT. demonstrates that any External Resources or portions of External Resources being registered as Capacity Resources to serve the Load of the LSE are not otherwise being used as capacity resources in any other RTO/ISO or in another state resource adequacy program; is available in the event of an Emergency; and performs an annual GVTC test and reports data via GADS. External Resources greater than or equal to 10 MW based on GVTC must submit generator availability data (including, but not limited to, NERC GADS) into a database through the Market Portal. Definition of Generation Resources does not include Intermittent Resources or Intermittent Generation. This 10 MW threshold applies to individual generator sizes and not to contracted capacity values in PPAs. OPS-12 Public Page 4-35 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 External Resources will be recognized in the LRZ zone where the resource sinks. Existing External Resources with firm and/or GFA rights to load will be treated as a zonal resource for that load’s LRZ zone subject to Grandmother Hedge if it existed prior to July 20, 2011. External Resources less than 10 MW based upon GVTC that begin reporting GADS data must continue to report such information. New External Resources must submit GVTC and if greater than or equal to 10 MW based on GVTC must submit GADS prior to being approved as a Capacity Resource. The XEFORd for new External Resources in service less than twelve full calendar months will be the class average for the resource type. An External Resource will use the class average value until 12 consecutive months of data is available and a new Planning Year has occurred. o Planning Year Testing: All External Resources being used as a Planning Resource are required to perform a real power test according to MISO’s Generator Test Requirements and submit the GVTC data to MISO’s PowerGADS no later than October 31st in order to qualify as a Planning Resource. The test shall be performed between September 1 and August 31 of the prior Planning Year and corrected to the average temperature of the date and times of MISO’s coincident Summer peak, measured at or near the generator’s location, for the last 5 years, or provide past operational data that meets these requirements to determine its GVTC and submit its GVTC data to MISO’s PowerGADS. External Resources must demonstrate capability on an annual basis as described below. OPS-12 Public Page 4-36 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 When to Perform and Submit a Generation Verification Test Capacity (GVTC) Generation Resources, External Resources, Demand Response Resources backed by behind the meter generation, or Behind the Meter Generation (BTMG) that qualified as Planning Resources for the current Planning Year shall submit their GVTC data no later than October 31st in order to qualify as a Planning Resource for the upcoming Planning Year. The real power test shall be performed or past operational data shall be between September 1st and August 31st prior to the upcoming Planning Year. A real power test is required to demonstrate a modification that increases the rated capacity of a unit, and then submit the revised GVTC to MISO. A real power test is required when returning from a “mothballed” state and the results of the GVTC should be submitted to MISO via the PowerGADS system. A real power test is required when any existing or new unit returns to MISO after an absence (including but not limited to, catastrophic events, or not qualified as a Planning Resource under Module E) or being qualified as a Planning Resource for the first time and must be submitted to MISO no later than March 1st prior to the Planning Year. The GVTC for a new External Resource is due before a Market Participant registers new External Resource in the MECT, and must be submitted by March 1st prior to the upcoming Planning Year. o See Appendix J of this BPM for links to MISO’s GVTC Manual and processes. Reporting Reporting is accomplished through MISO’s PowerGADS reporting system as described in MISO’s Net Capability Verification Test User Manual, which is OPS-12 Public Page 4-37 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 located on MISO’s website under Documents Planning > Resource Adequacy> Documents> GADS Information Link (Module E) > PowerGADS Documentation> Generator Testing Documents. A power purchase agreement (PPA) is a contract to buy/sell energy and/or capacity between parties. If the PPA involves a transfer of capacity within MISO’s then this transaction should be represented in the MECT as a ZRC. If the PPA involves External Resources, once such External Resources are registered and accredited, then the associated UCAP MWs may be converted to ZRCs in accordance with the procedures in Section 4.4. A PPA must be valid for the entire Planning Year if being used as a Planning Resource. PPAs that do not cover the entire Planning Year will not qualify as a Planning Resource under Module E. In order for a PPA to qualify as a Capacity Resource, it must demonstrate that it complies with the requirements found in Section 69A.3.1.c of the Tariff. 4.2.4.1 Submission of new External Resources Registrations A Market Participant must register their new External Resource via the LMR Registration screen in the MECT by March 1st prior to the Planning Year. In order to guarantee new Resources can be used in an LSE’s FRAP, registrations should be submitted no later than February 15th prior to the Planning Year. The registering entity must be a Market Participant prior to registering an External Resource. Any entity that is not a Market Participant, but desires to register an External Resource, must contact the Customer Registration team at register@misoenergy.org to become a Market Participant. The information registered in the Registration screen will require the Market Participant to certify that the registration information is accurate, complete, and that the qualified MWs from the External Resource are not being registered by another party or used in another Balancing Area for capacity purposes. Appendix F of this BPM contains the information that must be submitted by an MP through the MECT External Resource registration screen. MISO will review the External Resource registration information for completeness and accuracy OPS-12 Public Page 4-38 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 and ensure it complies with the qualification requirements for External Resources. MISO will notify the Market Participant within 15 days after the registration form was submitted as to whether or not the resource has been accredited as an External Resource, or whether there are any deficiencies that must be corrected. If the resource is accredited as an External Resource, it will be given a unique name for tracking purposes and made available in the MECT screens for use by the MP. 4.2.4.2 Termination of resources Accredited as External Resources Because External Resources need to be accredited annually, the “Effective Stop Date” will default to the last day of the applicable Planning Year . 4.2.4.3 Amendments to Accredited External Resource Registration Data The Market Participant can amend the registration for an External Resource for an upcoming Planning Year by providing MISO notification no later than March1st if the original registration was submitted by the deadlines. If a Market Participant needs to modify any of the non-end date information submitted in the registration, which may affect the External Resource’s qualification, including, but not limited to, a change in operation or has either an increase or decrease in it MW capability, then the Market Participant shall an amended registration information in the Registration screen by March 1st prior to a Planning Year in order for MISO to determine whether the resource still qualifies as an External Resource. 4.2.4.4 OPS-12 Renewal of External Resource for Subsequent Planning Years Public Page 4-39 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Each External Resource must be reviewed for accreditation as an External Resource on an annual basis. Renewal of External Resources must be requested by February 1st prior to the Planning Year. MISO will review the renewed External Resource registration information for completeness and accuracy and ensure it complies with the qualification requirements for an External Resource. MISO will notify the Market Participant within 15 days after the renewed registration form was submitted whether or not the External Resource has been accredited as an External Resource, or whether there are any deficiencies that must be corrected. If the External Resource is accredited as an External Resource, it will be given a unique name for tracking purposes and made available in the MECT screens for use by the MP during the applicable Planning Year. 4.2.4.5 Review of Power Purchase Agreements Effective in the Future Market Participants that have entered into power purchase agreement(s) for future planning years may request MISO to review the pertinent provisions of the agreements in order to make a preliminary determination of whether the agreement(s) would qualify as External Resources from power purchase agreement(s) as set forth in sections 69A.3.1.c.i through 69A.3.1.c.vii of the Tariff. Market Participants must submit a written request for review of such power purchase agreements to the MISO Manager of Resource Adequacy. MISO Resource Adequacy and Legal staff will review the submitted agreement(s) and respond within 60 days of receipt of the request. MISO will provide written confirmation as to whether MISO believes that the contract meets the current Tariff requirements. Any such determination is based upon the existing version of the Tariff, which may be modified from time to time subject to the acceptance of such modifications by the Federal Energy Regulatory Commission. The Market Participant requesting an advanced review of the their agreements will need to follow the procedures applicable to the planning period for which such External Resource is intended to be relied to meet Capacity requirements. This includes the provision of the appropriate GVTC and GADS data, and other requirements then in effect for registering a new External Resource as set forth OPS-12 Public Page 4-40 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 in the Tariff and in Section 4.2.4 of this BPM that is effective at the time of registration,, in order to have the External Resource modeled in the MECT and qualified as Capacity. 4.2.4.6 External Resources – UCAP Determination External Resources will be accredited at the Capacity Resource’s Unforced Capacity based on GVTC value(s), transmission service, and EFORd values of such External Resources based on the methodology documented in Appendix H of the RAR BPM of this BPM. MISO will determine UCAP values for External Resources that are Intermittent Generation as described in Section 4.2.2. 4.2.4.7 External Resources – Must Offer Obligation As described in detail in Section 6.1, the maximum must offer requirement applies to the registered Capacity of the External Resource. An MP that converts a Generation Resource’s UCAP MW into ZRCs must submit the full operable capacity of the Resource, but not less than the ICAP value registered Capacity of what was converted to ZRCs and make an Offer into the Day-Ahead Energy and each pre DayAhead and the first post Day-Ahead Reliability Assessment Commitment (RAC) for every hour of every day, except to the extent that the Generation Resource is unavailable due to a full or partial forced scheduled outage. The must-offer requirement applies to the Installed Capacity (ICAP) of an External Resource, and not the UCAP rating. Installed Capacity refers to the amount of ZRCs divided by (1-XEFORd) of the Capacity Resource. An MP that converts the External Resource UCAP MW into ZRC establishes a Must-Offer requirement. Offers in the Day-Ahead Energy Market can only be Normal Energy type with the transaction type of either fixed or dynamic. Dispatchable and market type of Day-Ahead cleared OPS-12 Public Page 4-41 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 schedules are accounted for in the first post Energy and Operating Reserve Market. In addition, the Normal Energy type with the transaction type of either Fixed or Dispatchable offers with market type of Real-Time Energy and Operating Reserve Market only will also be considered in Day-Ahead Reliability Assessment Commitment (FRAC) . Therefore, the must-offer requirement for External Resources in FRAC is met by being available for declared capacity emergencies via EOP-002. The MP that converts the External Resource UCAP MW to ZRC shall ensure the resource operator is reporting its outages and derates with their respective reliability coordinator via System Data Exchange (SDX). External Resources must be available to schedule Energy into MISO’s Region during emergencies if needed by MISO. EOP-002 includes a mechanism to schedule all External Resources into MISO’s BAA. BPM 007 Physical Scheduling Systems Section 15 explains how External Resources should be identified as Capacity Resources. External Resources should select “YES” in the Miscellaneous (MISC) field of the E-tag and the Token field must contain “MISOCR”. The NERC IDC (Interchange Distribution Calculator) name of the Planning Resource must be entered in the value field of the MISC section exactly as it appears in the approved registration in the MECT and Outage Scheduler (CROW) except that the name must be in all caps. External Resources that are Use Limited Resources must follow the Day-Ahead must-offer requirements for Use Limited Resources as documented in section 4.2.3.2 of this BPM. Compliance with “must offer” requirements will be evaluated by MISO on a nondiscriminatory basis. MISO will analyze the compliance with must-offers in both the Day-Ahead and RAC by taking into account information provided by MISO’s Outage Scheduler (CROW), NERC SDX and operational limitations, including, but not limited to, those related to fuel limited, energy output limited or Intermittent Generation. OPS-12 Public Page 4-42 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 4.2.5 DRR Type I and Type II – Qualification Requirements DRR Type I and Type II may qualify as Capacity Resources provided that: (All references to generation availability and testing in this section pertain to DRRs backed by generation.) DRR Type I and Type II (that are not Intermittent Generation and Dispatchable Intermittent Resources) must submit generator availability data (including, but not limited to, NERC GADS) into a database through the Market Portal. DRR Type I and Type II must demonstrate capability on an annual basis. Verification of DRR Type I and Type II capability will be in accordance with the guidelines established by the applicable Regional Entity, unless superseded by specific verification guidelines set by the applicable state authorities. New DRR Type I and Type II Resources must submit GVTC and if greater than or equal to 10 MW based on GVTC must submit GADS prior to being approved as a Capacity Resource. Network Contract Numbers cannot be used, the Transmission Service Request must either be Firm Point to Point or Firm Network Designated Monthly transmission service requests may be used as long as they cover the entire Planning Year in aggregate and are provided in the MECT. Internal purchase power agreements (PPAs) will not be qualified by MISO. New DRR Type I and Type II Resources must submit GVTC, and if greater than or equal to 10 MW based on GVTC, then these Resources must submit GADS prior to being approved as a Capacity Resource. OPS-12 Public Page 4-43 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 DRR Type I and Type II that are less than 10 MW based upon type and volume interconnection service and GVTC that begin reporting generator availability, must continue to report such data. DRR Type I and Type II are registered as documented in the Market Registration BPM. The XEFORd for new DRR Type I and Type II Resources in service less than twelve full calendar months will be the class average for the resource type. A DRR Type I and Type II Resource will use the class average value until 12 consecutive months of data is available and a new Planning Year has occurred. All DRR Type I and II backed by a generator are required to perform a real power test according to MISO’s Generator Test Requirements and submit the GVTC data to MISO’s PowerGADS no later than October 31st, in order to qualify as a Planning or Load Modifying Resource. When to Perform and Submit a Generation Verification Test Capacity (GVTC) Generation Resources, External Resources, Demand Response Resources backed by Behind the Meter Generation, or Behind the Meter Generation that qualified as Planning Resources for the current Planning Year shall submit their GVTC data no later than October 31st in order to qualify as a Planning Resource for the upcoming Planning Year. The real power test shall be performed or past operational data between September 1st and August 31st prior to the upcoming Planning Year shall be used. A real power test is required to demonstrate a modification that increases the rated capacity of a unit, and then submit the revised GVTC data to MISO by March 1st prior to the Planning Year. OPS-12 Public Page 4-44 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 A real power test is required when returning from a “mothballed” state and the results of the GVTC should be submitted to MISO via the PowerGADS system. A real power test is required when any existing or new unit returns to operational status after an absence (including but not limited to, catastrophic events, or not qualified as a Planning Resource under Module E) or being qualified as a Planning Resource for the first time. The GVTC data for a new Demand Response Resource is due to MISO at the time a Market Participant registers the resource in the Commercial Model and before the Market Participant elects the register the resource in the MECT. See Appendix J of this BPM for links to MISO GVTC Manual and processes. Reporting is accomplished through MISO’s PowerGADS reporting system as described in MISO’s Net Capability Verification Test User Manual, which is located on MISO’s website under Documents>Planning Resource Adequacy> Documents> GADS Information Link (Module E) > PowerGADS Documentation> Generator Testing Documents. 4.2.5.1 DRR Type I and Type II – UCAP Determination MISO will determine the UCAP value for each Demand Response Resources backed by behind the meter generation based on an evaluation of GVTC value and XEFORd values of such BTMG. If such behind the meter generation facility is interconnected to the Transmission System, MISO will consider the type and volume of the interconnection service when determining the Unforced Capacity. If GADS data is not required to be submitted by the MP, then a class average EFORd of the resource type will used to calculate the forced outage rate. A XEFORd value of zero will be applied to all DRR that interrupts or controls load. OPS-12 Public Page 4-45 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 UCAP MW options for units with derates prior to the GVTC test date is further explained in Appendix J.4 of the RAR BPM. 4.2.5.2 DRR TYPE I AND TYPE II – Must Offer As described in detail in Section 6.1 of this BPM, an MP that converts a Generation Resource’s UCAP MW into ZRCs must submit the full operable capacity of the Resource, but not less than the ICAP value of what was converted to ZRCs and make an Offer into the Day-Ahead Energy and each pre Day-Ahead and the first post Day-Ahead Reliability Assessment Commitment (RAC) for every hour of every day, except to the extent that the Generation Resource is unavailable due to a full or partial forced outage or scheduled outage The must offer requirement applies to the Installed Capacity of DRR Type I and Type II, and not the UCAP rating. Installed Capacity refers to the amount of ZRCs divided by (1 – XEFORd) of the Capacity Resource. The MP that converts a DRR Type I or Type II UCAP MWs into ZRCS must submit offers for an amount equal to the converted amount of capacity of the resource but no less than the ICAP value of what was converted to ZRCs for each hour of each day into the Day-Ahead Energy and all pre Day-Ahead and the first post Day-Ahead RAC, except to the extent that the DRR is unavailable due to a full or partial forced outage or scheduled outage and that the outage is reported into MISO’s Outage Scheduler to MISO. The must-offer thresholds established in Section 6.1 of Generation Resources (excluding this BPM will not be applied to DRR Type I and Type II) resources. OPS-12 Public Page 4-46 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 4.3 Non-Capacity Resources 4.3.1 Load Modifying Resource Obligations and Penalties Load Modifying Resources (LMRs) consist of accredited Demand Resource (DR) or Behind the Meter Generation (BTMG). A Demand Resource shall mean a resource registered with MISO defined as Interruptible Load or Direct Control Load Management and other resources that result in additional and verifiable reductions in end-use customer demand during an Emergency. An LMR that relies solely on a generator to reduce load or as a fallback for load control or interruption must register as a BTMG. Behind the Meter Generation is defined as a generation resource used to serve wholesale or retail load that is located behind a CPNode. BTMG is not included in MISO’s Dispatch Instructions. LMR differ from Capacity Resource in that they do not have a must offer requirement, however they must be available for use as registered as defined in this BPM during all types of Emergency events (including both capacity and transmission events) declared by MISO unless unavailable as a result of maintenance requirements or for reasons of Force Majeure. The LMR will be called but not required to respond if the Emergency call is outside the resource’s registration limitations (i.e. less than the registered time to respond, the event lasts longer than the registered duration, is made outside the Summer period or the resource has reached its registered number of deployments). MISO’s Emergency Operations Manuals, RTO-EOP-002 and RTO-EOP-004 include the procedures on how and when LMRs will be called on in an Emergency situation. Additionally, there are penalty provisions for LMR that fail to perform when called upon during Emergencies declared by MISO. This section details these and other requirements, obligations and provisions LMR must meet and maintain in order to qualify to provide capacity in the MISO Resource Adequacy construct. OPS-12 Public Page 4-47 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 DRR Type I and Type II that have converted UCAP to ZRCs are categorized as Capacity Resources under Module E (Section 69A.3.1.b) and therefore are not LMRs. An LMR is not required to be a Network Resource. A resource may qualify as an EDR under Schedule 30 regardless of whether it qualifies as an LMR under Module E. Also, dual registration as an EDR and an LMR is acceptable. A DRR Type I and Type II Resource can also register in the MECT as a Load Modifying Resource but can only convert a combined UCAP MWs to ZRCs not to exceed the maximum assigned value of the singular resource. Accredited LMRs that have been converted to ZRCs must be available as outlined above for use in the event of an Emergency declared by MISO. The Market Participant that has cleared ZRCs from an accredited LMR (or had its accredited DRs netted from its LSE Forecast Requirement) in the PRA would be subject to penalties if that LMR fails to respond in an amount greater than or equal to its target level of Load reduction for DRs (or target level of generation increase for BTMG as directed by MISO or the LBA) in accordance with Emergency operating procedures. The target level of Load reduction for a DR will take into account the specified firm service level it specified at registration. However, MISO will not assign LMR penalties to Emergency Demand Response (EDR) resources that have already been assessed penalties under Schedule 30 of the Tariff. Survey responses prior to an Emergency event will also be considered when evaluating whether target levels of generation increase or Load reduction have been met. The operators of LMRs that properly report to MISO and to the LBA that an LMR is unavailable or the LMR does not respond to the Transmission Provider’s dispatch instruction will have an opportunity to provide documentation of the specific circumstances that would justify exemption from such penalties. A penalty will not be assessed for any portion of the target level of Load reduction, for DR or target level of generation increase for a BTMG, which had already been accomplished for other reasons (i.e., for economic considerations, self-scheduling at or above the credited amount of BTMG, or local reliability concerns) at the time the request for OPS-12 Public Page 4-48 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 interruption is made. Likewise, for certain LMRs that are temperature dependant (e.g., a Demand Resource program involving air conditioning load), the target level of Load reduction or target level of generation increase may be adjusted in a manner defined in the measurement and verification procedures to reflect the circumstances at the time an LMR is called upon to reduce Load or increase generation for BTMG. A Market Participant that has cleared ZRCs in the PRA from an accredited LMR or netted accredited DRs against its Demand forecast will be subject to the penalties described in Section 69A.3.9 of the Tariff if the LMR fails to respond in an amount greater than or equal to the target level of a Load reduction for DR or target level of generation increase for a BTMG. Such LSE shall be assessed the costs that were otherwise incurred to replace the energy deficiency at the time the LMR was dispatched. 4.3.2 BTMG Qualification Requirements MPs with BTMGs can qualify as LMRs by: Registering BTMG through the MECT BTMG registration screen according to the process documented in Section 4.3.2.1. Confirming through the registration process such BTMG can be available to provide energy with no more than 12 Hours advance notice from MISO or the LBA and sustain energy production for a minimum of four (4) consecutive Hours for 5 events. Confirming through the registration process that the BTMG is capable of being interrupted and available at least the first (5) times during the Summer season when called on by MISO or the LBA for emergency purposes during the Planning Year. OPS-12 Public Page 4-49 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Confirming that the BTMG is equal to or greater than 100 kW (an aggregation of smaller resources that can produce energy may qualify in meeting this requirement if located in the same LRZ). Submitting generator availability data (including, but not limited to, NERC GADS) into a database through the Market Portal for non-intermittent BTMG greater than or equal to 10 MW based on GVTC]. Non-intermittent BTMG less than 10 MW based upon GVTC that begin reporting generator availability data must continue to report such information. Behind the Meter Generation that is an intermittent resource has to submit information in accordance with Section 4.2.2 of this BPM. For wind resources being registered as BTMG, the following information is required: o Resources with at least one year of metered values would submit 8760 metered values in MWs. In addition, MPs may provide hourly output at specific times for the top eight MISO daily peak from one year up to 5 previous years o Resources with less than one year of metered values would receive class average for the Initial Planning Year New BTMG resources must submit GVTC and if greater than or equal to 10 MW based on GVTC and must submit GADS prior to being registered as a LMR. The XEFORd for new BTMG Resources in service less than twelve full calendar months will be the class average for the resource type. A BTMG resource will use the class average value until 12 consecutive months of data is available and a new Planning Year has occurred. OPS-12 Internal purchase power agreements (PPAs) will not be qualified by MISO. Public Page 4-50 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Demonstrating capability for non-intermittent BTMG on an annual basis as described below. All BTMGs being used as a Planning Resource are required to perform a real power test according to MISO’s Generator Test Requirements and submit the GVTC data to MISO’s PowerGADS no later than October 31st in order to qualify as a Planning Resource. The test shall be performed between September 1 and August 31 of the prior Planning Year and corrected to the average temperature of the date and times of MISO’s coincident Summer peak, measured at or near the generator’s location, for the last 5 years, or provide past operational data that meets these requirements to determine its GVTC and submit its GVTC data to MISO’s PowerGADS. When to Perform and Submit a Generation Verification Test Capacity (GVTC) Generation Resources, External Resources, Demand Response Resources backed by behind the meter generation, or Behind the Meter Generation that qualified as Planning Resources for the current Planning Year shall submit their GVTC data no later than October 31st in order to qualify as a Planning Resource for the upcoming Planning Year. A real power test is required to demonstrate a modification that increases the rated capacity of a unit, and then submit the revised GVTC data. The real power test shall be performed or past operational data shall be from September 1st and August 31st immediately preceding the applicable Planning Year. A real power test is required to demonstrate a modification that increases the rated capacity of a unit, and then submit the revised GVTC. OPS-12 Public Page 4-51 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 o A real power test is required when returning from a “mothballed” state and submittal of the results of the GVTC to MISO via the PowerGADS system. o A real power test is required when any existing or new unit returns to MISO after an absence (including but not limited to, catastrophic events, or not qualified as a Planning Resource under Module E) or being qualified as a Planning Resource for the first time. The GVTC for a new or existing BTMG with increased capability is due before a Market Participant registers its new BTMG in the MECT, must be submitted by March 1st prior to the Planning Year that the BTMG is effective in the Module E Capacity Tracking Tool. See Appendix J of this BPM for links to MISO GVTC Manual and processes. Reporting is accomplished through MISO’s PowerGADS reporting system as described in MISO’s Net Capability Verification Test User Manual, which is located on MISO’s website under Documents Planning > Resource Adequacy> Documents> GADS Information Link (Module E) > PowerGADS Documentation> Generator Testing Documents. 4.3.2.1 Submission of New BTMG Registrations A MP will register its new BTMG via the LMR Registration screen in the MECT by March 1st prior to the Planning Year. The registering entity must be a MP prior to registering a BTMG. In order to guarantee new Resources can be used in an LSE’s FRAP, registrations should be submitted no later than February 15th prior to the Planning Year. An entity that is not a MP, but desires to register a BTMG, must contact the Customer Registration team at register@misoenergy.org to become a MP. During the registration process the MP will be required to certify that the registration information is accurate, complete, and that the qualified OPS-12 Public Page 4-52 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 MWs from the BTMG are not being registered by another party. Appendix E of this BPM contains the information that must be submitted by an MP through the MECT LMR registration screen. MISO will review the BTMG registration information for completeness and accuracy and ensure it complies with the qualification requirements for BTMG. MISO will notify the MP within 15 days after the registration form was submitted regarding whether or not the BTMG has been accredited as an LMR, or whether there are any deficiencies that must be corrected. If the BTMG is accredited as an LMR, it will be given a unique name for tracking purposes and made available in the MECT screens for use by the MP. 4.3.2.2 Termination of BTMG Accredited as LMR Because BTMGs need to be accredited annually, the “Effective Stop Date” will default to the last day of the applicable Planning Year. 4.3.2.3 Amendments to Accredited BTMG Registration Data The Market Participant can amend the registration for a BTMG for an upcoming Planning Year by providing MISO notification no later than March 1st if the original registration was submitted by the February 1st due date. . The Market Participant may modify any of the non-end date information submitted in the registration, which may affect the BTMG’s qualification, including, but not limited to, a change in operation or has either an increase or decrease in it MW capability. The Market Participant shall submit new or amended registration information in the MECT by March 1st prior to a Planning Year in order for MISO to determine whether the resource still qualifies as a BTMG. The Market Participant will still need to provide MISO with a GVTC by the original test date as outlined in the BPM. Any modifications in the capability of an existing BTMG must have updated test and registration information submitted to MISO via the MECT by March 1st. If Market Participant wishes to retire, suspend or mothball a BTMG, the MP must replace retired or mothballed resources that were cleared in the Planning Resource Auction via the MECT. MPs must notify Resource Adequacy (7) Business Days prior to replacing any resources. The OPS-12 Public Page 4-53 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 ZRCs which are being substituted must be in same Local Resource Zone as the BTMG being retired, suspended, or mothballed and such ZRCs may not be used elsewhere to satisfy obligations unless the BTMG was partially used. Only the remaining ZRCs of a BTMG that was partially used, can be used to help meet the performance requirements of the original BTMG cleared in the PRA, or used in a FRAP. 4.3.2.4 Renewal of BTMG for subsequent Planning Years BTMG must be reviewed for accreditation as an LMR on an annual basis. A MP can request renewal of BTMG accreditation for subsequent Planning Years through the MECT registration screens. Renewal of BTMG must be requested by February 1st prior to the Planning Year. NOTE: BTMGs must submit GVTC and/or operational data by the October 31 deadline, per Section 4.3.2., in order to have UCAP values determined. MISO will review the revised BTMG registration information for completeness and accuracy and ensure it complies with the qualification requirements for BTMG. MISO will notify the MP within 15 days after the revised registration form was submitted regarding whether or not the BTMG has been accredited as an LMR, or whether there are any deficiencies that must be corrected. If the BTMG is accredited as an LMR, then it will be given a unique name for tracking purposes and be made available in the MECT screens for use by the MP during the applicable Planning Year. 4.3.2.5 Behind the Meter Generation – UCAP Determination The UCAP value for a BTMG is based on an evaluation of the applicable type and volume of interconnection service, GVTC, and XEFORd value of such BTMG, as described below. The Unforced Capacity methodology is implemented to address the fact that not all BTMG contribute equally to Resource Adequacy. By adjusting the capacity rating of a unit, based on its XEFORd, UCAP provides a means to recognize the relative contribution that each resource makes towards Resource Adequacy. The PRM is similarly adjusted by the weighted average XEFORd of all the pooled resources, and the generating units with better than average availability will reflect higher value than units with below average availability. OPS-12 Public Page 4-54 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 UCAP MW options for units with derates prior to the GVTC test date are further explained in Appendix J.4 of the RAR BPM. 4.3.2.6 BTMG Deliverability BTMG should be deliverable to Load located within MISO’s Region using one of the following: BTMG that is located at the same CPNode as the LSE’s demand LSE has obtained firm transmission service from the BTMG to its load BTMG may be used by any Network Customer within the LBA in which the BTMG is located provided that the Network Customer identifies the BTMG as a Network Resource on MISO’s OASIS. Network Contract Numbers cannot be used, the Transmission Service Request must either be Firm Point to Point or Firm Network Designated The load is a network customer and the BTMG has been determined to be aggregate deliverable by acquiring Network Resource Interconnection Service, or the Market Transition Deliverability test provided that the BTMG is interconnected to MISO’s Transmission System,. 4.3.2.7 Measurement and Verification of BTMG The measurement and verification procedures developed by MISO shall take into account any applicable state regulatory, RE, or other non-jurisdictional entities requirements regarding duration, frequency and notification processes for the candidate BTMG and such details will be included in future versions of this BPM. OPS-12 Public Page 4-55 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 For BTMG, the MP registering the BTMG must measure and record the electrical output of the generator(s) during the hour preceding an Emergency event and all hours the event is active. The MP shall submit meter data to MISO within 60 days following an Emergency event in which the BTMG that was cleared in the PRA was deployed. MISO will review the meter data to verify that the BTMG increased energy output to the level instructed by the LBA. BTMG consisting of one or more generating units that have been identified by MISO must have metering (MWh) equipment for operational security purposes. BTMG consisting of multiple generating units at a single site that have been identified by MISO must have metering (MWh) equipment and may be metered as a single unit, however, multiple BTMG units that have a single meter will be treated as a single unit for purposes of determining penalties as described in Section 69A.3.9 of the Tariff. MISO may periodically audit MP performance reports and other data to ensure that it is consistent with the requirements described in this BPM. All information submitted by the MP is subject to audit by MISO. Disputes concerning erroneous performance reporting shall be resolved through MISO’s existing dispute resolution procedures by submitting a service request through MISO’s portal (except for disputes between the MP and retail customer, which are not the responsibility of MISO). 4.3.3 Demand Resource – Qualification Requirements MPs with DR can qualify the DR as an LMR by: Registering the DR through the MECT DR registration screen according to the process documented in Section 4.3.3.1 of this BPM. Confirming through the registration process such DR can be available to reduce Demand with no more than twelve (12) Hours advance notice from MISO or the LBA and sustain the reduction in Demand for a minimum of four (4) consecutive Hours. OPS-12 Public Page 4-56 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Confirming through the registration process that the DR is not dependent on the dispatch of a BTMG owned or operated by the wholesale or retail customer. Confirming through the registration process that the DR is equal to or greater than 100 kW (an aggregation of smaller resource that can reduce Demand may qualify in meeting this requirement). Confirming through the registration process that the DR is capable of being interrupted at least the first (5) times during the Summer season when called on by MISO or the LBA for Emergency purposes during the Planning Year. Confirming that the Demand Resource permits the Market Participant to interrupt the Load. Documenting capability to reduce demand to a targeted Demand reduction level or firm service level using one of the following options: o Provide documentation from the state that has jurisdiction that provides the amount and type of DR and the procedures for achieving the Demand reduction; o Verification from a third party auditor that is unaffiliated with the MP that documents the DR’s ability to reduce to the targeted Demand reduction level or firm service when called upon to perform by MISO or the LBA. o Provide past performance data that demonstrates the DR’s ability to reduce to the targeted Demand reduction level or firm service level when called upon to perform by MISO or the LBA. If past performance data does not exist from the previous Planning Year, then a mock test can be used to support the validity of the DR. The mock test should employ all OPS-12 Public Page 4-57 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 systems necessary to initiate a Demand reduction short of actual Demand reduction o For the 2013-2014 Planning Year, test, performance data, third party audit or other documentation supporting the registered MW should be from June 1, 2012 to March 1, 2013. Beginning in Planning Year 20142015 and thereafter, test, performance data, third party audit or documentation supporting the MW being registered should be from September 1 and August 31st immediately preceding the applicable Planning Year. Results should be submitted to MISO by October 31st . Documenting the Measurement and Verification (M&V) protocol that will be used to determine if such DR performed when called upon by MISO or the LBA during Emergencies. A DR that is sensitive to temperature changes must identify the extent of such temperature sensitivity with sufficient detail to enable MISO to verify whether the DR would be subject to the penalties set forth in Section 69A.3.9 of the Tariff. Temperature sensitivity must at a minimum include identifying the measure used for temperature changes and elasticity of the LSE’s load to weather. An MP that registers a DR as a Planning Resource must confirm that the DR is able to meet all of the requirements in Section 69A.3.5 of the Tariff. 4.3.3.1 Demand Resource Registration Process DR can be registered to be used to net against and LSE’s Demand forecast, or to be used as a resource to receive UCAP MW that can be converted to ZRCs. The MP must choose one of these options at the time of registration. A DR that an MP elects to use as a Planning Resource by creation of ZRCs may not also be netted from the LSE’s forecasted Demand. MISO will subtract accredited DR from an LSE’s Forecast LSE Requirement if the LSE chooses the “netting” option during registration. OPS-12 Public Page 4-58 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 4.3.3.2 Submission of new DR Registrations A MP may register their new DR via the LMR Registration screen in the MECT by March 1st prior to the Planning Year. In order to guarantee new Planning Resources can be used in an LSE’s FRAP, registrations should be submitted no later than February 15th prior to the Planning Year. The registering entity must be a MP prior to registering a DR. Any entity that is not a MP, but desires to register a DR, should contact the Customer Registration team at register@misoenergy.org to become a MP. The MP will be required to certify that the registration information is accurate, complete, and that the qualified MWs from the DR are not being registered by another party. Appendix D of this BPM contains the information that must be submitted by an MP through the MECT LMR registration screen for DR. MISO will review the DR registration information for completeness and accuracy and ensure it complies with the qualification requirements for DR. MISO will notify the MP within 15 days after the registration form was submitted regarding whether or not the DR has been accredited as an LMR, or whether there are any deficiencies that must be corrected. If the DR is accredited as an LMR, it will be given a unique name for tracking purposes and made available in the MECT screens for use by the MP. 4.3.3.3 Termination of Demand Resource Accredited as LMR Because DRs need to be accredited annually, the “Effective Stop Date” will default to the last day of the applicable Planning Year. 4.3.3.4 Amendments to Accredited DR Registration Data The Market Participant can amend the registration for a DR for an upcoming Planning Year by providing MISO notification no later than March 1st if the original registration was submitted by the February 1st due date. OPS-12 Public Page 4-59 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 The MP may modify any of the non-end date information submitted in the registration, which may affect the DR’s qualification, including, but not limited to, a change in operation, number of interruptions, advisory notice period, maximum duration, or accreditation or has either an increase or decrease in either its targeted MW level or firm service level. The MP shall submit amended registration information in the Registration screen by March 1st prior to the Planning Year in order for MISO to determine whether the resource still qualifies as an LMR. If Market Participant wishes to discontinue a DR that cleared in the Planning Resource Auction during the Planning Year, the Market Participant must replace the DR with a resource in the same LRZ via the MECT. The MP should notify Resource Adequacy (7) Business Days prior to replacing the DR. The ZRCs which are being substituted must be in same Local Resource Zone as the DR being discontinued and may not be used elsewhere to satisfy obligations unless the DR was partially used. Only the remaining ZRCs of a DR partially used can be used help meet the performance requirements of the original DR cleared in the PRA or used in a FRAP. 4.3.3.5 Renewal of DR for subsequent Planning Years A DR must be reviewed for accreditation as an LMR on an annual basis. A MP can request renewal of DR accreditation for subsequent Planning Years through the MECT registration screens. Renewal of DR must be requested by February 1st prior to the Planning Year. MISO will review the renewed DR registration information for completeness and accuracy and ensure it complies with the qualification requirements for DR. MISO will notify the MP within 15 days after the renewed registration form was submitted regarding whether or not the DR has been accredited as an LMR, or whether there are any deficiencies that must be corrected. If the DR is accredited as an LMR, it will be given a unique name for tracking purposes and made available in the MECT screens for use by the MP during the applicable Planning Year. OPS-12 Public Page 4-60 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 4.3.3.6 Demand Resources – UCAP Determination A Demand Resource must be registered and accredited with MISO and will receive 100 percent of its capacity rating for the initial Planning Year. Capacity values for Demand Resources will be based on documentation from the state, third party auditor, or past performance, or mock test. MISO will determine through the registration process whether the BTMG or DR qualifies as an LMR under Module E. The resource may also qualify as an EDR under Schedule 30 regardless of whether it qualifies as an LMR under Module E. Dual registration as an EDR and an LMR is also acceptable. Once the LMR and its MWs are entered into the MECT and accredited by MISO, then the MP that registered the LMR can elect to convert all or part of the LMR’s accredited MWs into ZRCs. The LSE that clears ZRCs in the PRA from an accredited LMR or Demand Resource will be subject to the penalty provisions contained in Section 69A.3.9 of the Tariff, for not responding during an Emergency. 4.3.3.7 Demand Resource Deliverability The owner of the ZRCs that cleared in the PRA from a DR may not use the DR outside of the LRZ in which the DR physically resides. 4.3.3.8 Measurement and Verification of Demand Resource The measurement and verification procedures developed by MISO shall take into account any applicable state regulatory, RE, or other non-jurisdictional entities requirements regarding duration, frequency and notification processes for the candidate Demand Resources and such details will be included in future versions of this BPM. The Baseline Usage or Customer Baseline for a DR is the average hourly load, rounded to the nearest kWh, for each of the 24 hours in a day for such Resource. OPS-12 Public Page 4-61 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 The Customer Baseline will be calculated by the MP registering the DR after an Emergency is called. The Customer Baseline used for computing performance for Demand Resources shall consist of eligible weekdays (weekdays that are non-Demand Response Holidays and noninterruption days). A Customer Baseline is required for a Demand Resource that is listed in an LSE’s forecasted Load. For an asset with no previously computed baseline, the Customer Baseline is based upon a simple average and will be calculated for each hour in a day, based on meter data from the ten business days prior to an event, which is referred to as the default baseline. This default baseline calculation will be used unless an alternative baseline calculation is proposed in the registration process and accepted by MISO. The MP that registered the DR will collect and provide the meter data and its Customer Baseline. The MP shall document these comparisons and submit the results to MISO within 60 days of the declared Emergency during which a DR that cleared in the PRA was deployed. In the event of an Emergency, MISO will review metering data to verify that the Demand Resource performed. 4.3.4 Energy Efficiency Resources Energy Efficiency (EE) Resources are installed measures on retail customer facilities that achieve a permanent reduction in electric energy usage while maintaining a comparable quality of service. The EE Resource must achieve a permanent, continuous reduction in electric energy consumption (during the defined EE Performance Hours) that is not reflected in the peak load forecast used for the Planning Resource Auction for the Planning Year for which the EE OPS-12 Public Page 4-62 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Resource is proposed. The EE Resource must be fully implemented at all times during the Planning Year, without any requirement of notice, dispatch, or operator intervention. Examples of EE Resources are efficient lighting, appliance, or air conditioning installations; building insulation or process improvements; and permanent load shifts that are not dispatched based on price or other factors. All of the requirements to offer or commit an EE Resource in MISO’s capacity planning market are detailed the sections below. One of the major requirements includes the measurement and verification of the EE Resource’s Nominated EE Value for the Planning Year. The Nominated EE Value is the expected average demand (MW) reduction during the defined EE Performance Hours in the Planning Year. The EE Performance Hours are between the hour ending 13:00 Eastern Prevailing Time (EPT) and the hour ending 19:00 EPT during all days from June 1 through August 31, inclusive, of such Planning Year, that are not a weekend or federal holiday. A Measurement & Verification (M&V) plan describes the methods and procedures for determining the Nominated EE Value of an EE Resource and confirming that the Nominated EE Value is achieved. The EE Resource provider must submit an initial Measurement & Verification plan for the EE Resource no later than 30 days prior to the PRA in which the EE Resource is to be initially offered. The EE Resource provider must submit an updated Measurement & Verification plan for the EE Resource no later than 30 days prior to the next PRA in which the EE Resource is to be subsequently offered. Post-installation of the EE Resource, the EE Resource provider must submit an initial Post-Installation M&V Report for the EE Resource prior to the first Planning Year that the EE Resource is committed to PRA. The EE Resource Provider must submit updated Post-Installation M&V Reports prior to each subsequent Planning Year that the resource is committed. Failure to submit an updated PostInstallation M&V Report prior to a subsequent Planning Year or failure to demonstrate that postinstallation M&V activities were performed in accordance with the timeline in the approved M&V Plan will result in a Nominated EE Value equal to zero MWs of ZRCs for the Planning Year. OPS-12 Public Page 4-63 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 The last Post-Installation M&V Report submitted and approved by MISO prior to the Planning Year that the EE Resource is committed will establish the Nominated EE Value that is used to measure PRA commitment compliance during the Planning Year. Details regarding PRA commitment compliance and the associated penalty for failure to deliver the unforced value of a PRA capacity commitment are detailed below. MISO reserves the right to audit the results presented in an initial or updated Post-Installation M&V Report. The M&V Audit may be conducted at any time, including during the defined EE Performance Hours. If the M&V Audit is performed and results finalized prior to the start of a Planning Year, the Nominated EE Value confirmed by the Audit becomes the Nominated EE Value that is used to measure PRA commitment compliance during the Planning Year. If the M&V Audit is performed and results are finalized after the start of a Planning Year, the Nominated EE Value confirmed by the M&V Audit becomes the Nominated EE Value prospectively for the remainder of that Planning Year Energy Efficiency installations that are installed prior to any given Planning Year are eligible to participate in PRAs for that Planning Year and three subsequent Planning Years. For example, an Energy Efficiency resource installed and qualified prior to June 1, 2013, could participate in the 2013/14, 2014/15, 2015/16, and 2016/17 Planning Year PRAs provided the Energy Efficiency resource registers and meets the qualification requirements for each Planning Year. After four years, the Energy Efficiency resource could no longer be used as a Planning Resource but would continue to be included as a reduction in the demand forecast. 4.3.4.1 Description of M&V Plan The Measurement and Verification (M&V) Plan is a document that defines project-specific M&V methods and techniques that will be used to determine and verify the Nominated EE Value (i.e., the demand reduction) resulting from an EE Resource. A single M&V Plan may be submitted to cover multiple EE Resources. The single M&V Plan must clearly document the Nominated EE Value of each EE Resource covered in the M&V Plan. OPS-12 Public Page 4-64 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 In addition to providing accurate and conservative methods to calculate the Nominated EE Value, a good M&V Plan is clear, consistent, and repeatable. All the assumptions, procedures, and data for the M&V Plan should be recorded properly so that they may be easily referenced and verified by others. The data included should be sufficient for a third party to audit the M&V procedures and verify the Nominated EE Value of an EE Resource. M&V activities include, but are not limited to, site surveys, demand and energy measurements, metering of key variables, data analyses, calculations, and quality assurance procedures. All of these key components need to be adequately detailed in the M&V Plan. 4.3.4.2 General Requirements of M&V Plan An M&V Plan submitted to MISO must include: o A summary of the methodologies used to determine the Nominated EE Value. o A description of why the methodology or combination of methodologies selected is the most appropriate, relative for its project. o A description of any variables that affect the project’s electrical demand (such as outside temperature, time of day, process changes, occupancy, etc.) that will be measured or monitored and used in the determination of the Nominated EE Value during the defined EE Performance Hours. o All substantive assumptions for the project’s Nominated EE Value, including but not limited to, baseline demand consumption, post- installation demand consumption, process changes, and measure life. o Specifications of the equipment or types of equipment for projects being installed and/or modified. The information may include, but is not limited to, engineering analysis utilized to specify equipment, program design measures and or practices, or applications of equipment, measure or practice relative to end use or processes in the facility. o OPS-12 Coincident with MISO’s peak Public Page 4-65 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 If one or more of the variables that will be measured or monitored and/or assumptions that will be used in the determination of the EE Resource’s Nominated EE Value during the defined EE Performance Hours are not known at the time the EE Resource provider submits its initial M&V Plan to MISO for review and approval, then the EE Resource provider may supply alternative information and/or forecasts and indicate the portion of the Nominated EE Value associated with such measurement and monitoring variables and/or assumptions and explain the basis for such forecasts. The M&V Plan may also include the following: (1) References to engineering best practices in the Measurement and Verification literature, reference reports, or state of the art techniques to demonstrate that its proposed Measurement and Verification approach is appropriate for the Energy Efficiency Resource type and will produce an accurate and reliable Nominated EE Values. (2) A description of the technical capabilities of its project team and subcontractors to implement its proposed methodology. 4.3.4.3 Initial M & V Plan Components The following are the project level and measurement level components that are required to be contained in the initial M&V Plan. Each project level and measurement level component includes a description of the required information. 4.3.4.4 Project Level Components The project level components lay the groundwork for obtaining information about the project and provide a shared understanding about its objectives, sponsorship, costs, benefits, timeframes, resources and mandate. All of the project level components of the M&V Plan should be complete in the initial M&V Plan. OPS-12 Public Page 4-66 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Project Description/Executive Summary Company name Project name Submission date Company address and contact information Project goals Energy Efficiency Application – how it reduces demand during defined EE Performance Hours Applicable Energy Efficiency or performance standards (i.e., building codes, appliance standards, or other relevant standards that are in effect at the time of the installation, as known at the time of commitment) Anticipated energy, demand and cost savings for each EE application and total anticipated savings Anticipated costs for Measurement and Verification Location of EE Resource (LRZ) Anticipated Nominated EE Value of EE Resource 4.3.4.5 Schedule Timeline for EE installation and Measurement and Verification activities. 4.3.4.6 Measurement Level Components The measurement level components define the measurement and verification process(es) selected and provide detailed rationale for the selection. The following measurement level components must be included in the Initial M&V Plan. The information submitted in these components should be refined, when appropriate, with each Updated M&V plan submittal. OPS-12 Public Page 4-67 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 4.3.4.7 Measurement Description Specific details about each EE project Demand, Energy, & Cost Savings to be claimed Rationale for selected form of measurement 4.3.4.8 Equipment Specifications and Documentation History of equipment to be replaced or modified Equipment standards 4.3.4.9 Measurement and Verification Approach Measurement and Verification Option General description of approach Monitoring parameters and variables Monitoring interval and period Measurement equipment specifications Measurement data collection and management Data validation, editing and estimating plan Accuracy of Monitoring and Verification method Savings uncertainty and confidence level Factors most uncertain or difficult to quantify 4.3.4.10 Assumptions Baseline and post-installation assumptions that affect demand and energy consumption (building occupancy schedules, equipment efficiencies, equipment operating strategies, load shapes, weather data, etc.) 4.3.4.11 OPS-12 Measurement and Verification Activities: Baseline Period Public Page 4-68 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Who will do M&V Activities List of activities before and after installation List of variables affecting demand and energy consumption and how they will be quantified Critical baseline condition factors 4.3.4.12 Measurement and Verification Activities: Post-Installation Period List of variables affecting energy consumption, variance from baseline case, and how they will be quantified Evidence that proper equipment/systems were installed, are operating correctly, and have the potential to generate the predicted savings (verification methods include surveys, inspections, spot measurements, and short-term metering.). New equipment surveys Critical post-installation condition factors Activities to ensure equipment operating as intended 4.3.4.13 Calculations & Adjustments Equations, calculations and analysis procedures for baseline and post-installation demand and energy consumption OPS-12 How performance models will be developed Description of population(s) Sample size calculations Method of sampling How demand and energy savings will be calculated How adjustments will be made Public Page 4-69 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 4.3.4.14 Metering Plan Who will provide and maintain metering equipment Specifications of metering equipment, accuracy, calibration procedures How data will be collected, maintained and reported Accuracy and quality assurance procedures 4.3.4.15 Updated M&V Plan Components An updated M&V Plan must include any updates to the project level & measurement level components that were included in the initial M&V plan or prior updated M&V plan. The updated M&V plan must include: Cover page with list of changes/updates contained in the updated M&V plan Details of any changes between the prior M&V plan, including any changes to the project status, and any changes to the demand and energy savings Updated/refined Nominated EE Value calculations, including any baseline adjustments performed. Initial Post-Installation M&V Report Components Post-installation measurement and verification activities are conducted to ensure that proper equipment/systems were installed, are operating correctly, and have the potential to generate the Nominated EE Value of the EE Resource. Verification methods include surveys, inspections, spot measurements, and short-term metering. An initial post-installation M&V report must include any updates to the project level & measurement level components that were included in the prior updated M&V plan. The initial post-installation report should include: Cover page with list of changes/updates contained in the initial post-installation M&V report Details of any changes between the prior updated M&V plan and as-built conditions, and any changes to the estimated demand and energy savings OPS-12 Public Page 4-70 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Detailed list of installed equipment Documentation of all post-installation verification activities (verifying that the equipment/systems were installed and are operating) Documentation of performance measurements conducted to validate the Nominated EE Value of the EE Resource (if applicable in accordance with the approved M&V plan) Detail any changes to the Nominated EE Value of the EE Resource 4.3.4.16 Updated Post-Installation M&V Report Components An updated post-installation M&V report should include any updates to the initial postinstallation report or a prior updated post-installation report. The updated post-installation report should include: Cover page with list of changes/updates contained in the updated postinstallation M&V report Documentation of all post-installation verification activities (verifying that the equipment/systems are still installed and operating) Documentation of performance measurements conducted to validate the Nominated EE Value of the EE Resource (if applicable in accordance with the approved M&V plan) OPS-12 Detail any changes to the Nominated EE Value of the EE Resource. Public Page 4-71 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 4.4 Confirmation and Conversion of UCAP MW To create a ZRC, a MP must convert UCAP MW from each qualified Planning Resource to ZRC through the MECT UCAP/ZRC conversion screen. A ZRC represents 1 MW-day of qualified unforced capacity from a Planning Resource for a specific Planning Year, tracked to the nearest tenth of a MW, pursuant to the applicable ZRC qualification procedures described below. All types of Planning Resources are tracked in the MECT, which tracks Module E resources used for compliance against an LSE’s obligations. When ZRCs are converted from UCAP by the Planning Resource owner, the ZRCs are populated in that MP’s available ZRC account. MISO will keep track of how many ZRCs the MP has created, and how many remaining UCAP MWs for each Planning Resource are available for conversion to ZRCs. Once created, MISO will track ZRCs back to the specific Planning Resources that they were created from in order to assist with establishing clearing requirements, the auction clearing process and market mitigation monitoring. As a condition of converting available UCAP MWs of a Capacity Resource into ZRCs, the MP must comply with all requirements for Planning Resources in the Tariff including but not limited to Section 69A.5, the must-offer requirement. A MP must unconvert any uncleared ZRCS in order not to be subject to the must offer requirement. MPs will have until May 30th to unconvert any uncleared ZRCs. OPS-12 Public Page 4-72 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 4.5 ZRC Transactions 4.5.1 Transfer of ZRCs Available ZRCs can be transferred between MPs using the MECT. This is accomplished in the ZRC Transactions’ tab in the MECT. Both the ‘Buyer’ and ‘Seller’ must confirm a transfer before the transfer will occur. Once the transaction has been confirmed by both parties the ZRC transaction volumes documented will be subtracted from the seller’s available ZRC account and added to the buyer’s available ZRC account. The MECT allows transactions based on type of ZRCs. 4.5.2 Conversion of ZRCs to UCAP MW An owner of ZRCs that also owns Planning Resources from which any ZRCs have been converted, may convert uncleared ZRCs from the same resource or any other resource in the same LRZ back to UCAP MW via the MECT UCAP/ZRC conversion screen if the resources do not clear in the Planning Resource Auction. The conversion of ZRCs may be directed to any specified resource provided that: (a) the resource previously was used to create ZRCs; and (b) that the increase in remaining UCAP MW from the conversion when added to the currently remaining UCAP MW eligible for conversion to ZRCs does not exceed the maximum UCAP MW for the resource. OPS-12 Public Page 4-73 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 5. Resource Adequacy Requirements 5.1 Overview MISO’s Resource Adequacy construct ensures that adequate Planning Resources are maintained for each of the seven Local Resources Zones (LRZs) to meet the MISO footprint’s Planning Reserve Margin Requirement (PRMR). An LSE can meet its PRMR by the following ways: (1) Self-scheduling (2) Fixed Resource Adequacy Plan (FRAP) (3) Participating in the Planning Resource Auction (PRA) (4) Paying the Capacity Deficiency Charge (CDC) 5.2 Local Resource Zones MISO developed Local Resource Zones (LRZ) to reflect the need for an adequate amount of Planning Resources to be located in the right physical locations within MISO Region to reliably meet Demand and LOLE requirements. MISO will provide the details of the Local Resource Zones no later than November 1st of the year prior to a Planning Year. The geographic boundaries of each of the LRZs will be based upon analysis that considers: (1) the electrical boundaries of Local Balancing Authorities; (2) state boundaries; (3) the relative strength of transmission interconnections between Local Balancing Authorities; (4) the results of previous LOLE studies; (5) the relative size of LRZs; and (6) market seams compatibility. MISO may reevaluate the boundaries of LRZs if there are changes in MISO Region, based upon the OPS-12 Public Page 5-1 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 preceding factors, including but not limited to, significant changes in membership, the Transmission System, and/or Resources. Depiction of LRZs (based upon 2010 data) : OPS-12 Public Page 5-2 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 5.2.1 Change in LRZ Configuration MISO, working with stakeholders, may change the configuration of the LRZs due to changes in system topology or configuration. Changes to LRZ configuration will only be applicable to future Planning Years that have not already been cleared through the PRA. 5.2.1.1 Nested Local Resource Zones If, through the planning process, MISO identifies an area of congestion within a defined LRZ, then MISO may create a new nested LRZ within that area. A nested LRZ may be carved out of a LRZ if the import and/or export limits materially differ from the LRZ. For each identified nested LRZ, a Capacity Export Limit (CEL), Capacity Import Limit (CIL), and Local Reliability Requirement (LRR) will be established for use in the PRA. 5.2.1.2 Calculation of Transfer Limits of the Local Resource Zone MISO will determine the CEL and CIL for a LRZ for a Planning Year using the following process: Use the Planning Year MISO Transmission Expansion Plan (MTEP) reliability model Model MTEP Appendix A facilities, considering facility in service dates All in service Planning Resources and Planning Resources in the Generator Interconnection Queue with a signed Interconnection Agreement and an in-service date in the relevant Planning Year Perform First Contingency Total Transfer Capability (FCTTC) analysis for each LRZ, by modeling NERC Category A (N-0) and Category B (N-1) contingencies Model generation-to-generation transfers Calculate FCTTC for each LRZ to and from the balance of LRZ using a One to all for export; and using an All to one for import) The outcome of this process will identify a CEL and CIL for each of the LRZs. OPS-12 Public Page 5-3 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 5.2.1.3 Establishment of Local Reliability Requirement MISO will establish a Local Reliability Requirement (LRR) for each LRZ by determining the quantity of Unforced Capacity needed such that an LRZ achieves an LOLE of 0.1 day per year, without consideration of transmission ties to systems outside of the LRZ. The LRR will be established using the following iterative process: Use the LOLE model in MARS to determine the resources required in the LRZ to maintain 1 day in 10 years LOLE, assuming the LRZ has no transmission ties to the outside world. Each LRZ contains the same load and physical resources from the PRM Analysis. For modeling purposes the LRZ is represented as isolated from the rest of MISO by assuming no transmission ties. The LOLE model will be run through multiple iterations successively adding resources until the LRZ achieves the 1 day in 10 years LOLE criteria with no external ties. o A Load Forecast Uncertainty (LFU) factor will be applied for each Zone. In general these are expected to be greater than the MISO wide LFU applied for the total MISO system wide PRM determination. o The initial iteration of the LOLE model will assume 0 MW of resources within the LRZ, and then, starting with the largest Unforced Capacity rated resource located in the LRZ, MISO will sequentially add additional resources (or fractions thereof) in descending order of MW of Unforced Capacity located in the LRZ until the LOLE is 0.1 day per year for the LRZ. o If the LRZ does not have sufficient resources located in the LRZ to achieve the LOLE of 0.1 day per year, then additional proxy resources (of typical size and typical EFORd for the particular LRZ) will be added until the LRZ would achieve the LOLE of 0.1 day per year. A fraction of the OPS-12 Public Page 5-4 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 final proxy resource will be added to achieve exactly the LOLE of 0.1 day per year for the LRZ. The formula for the LRZ’s LRR is as follows: LRRz1 = (Largest Unforced Capacity rated resourcez1 + 2nd Largest Unforced Capacity rated resourcez1 + 3rd largest Unforced Capacity rated resourcez1 + …, including if necessary, any proxy resources) such that the LOLEz1 = 0.1 day per year 5.2.1.4 Establishment of Local Clearing Requirement The final step is calculating an LRZ’s LCR is to account for the external transmission ties by reducing the LRR by the capacity import limit determined in accordance with Section 3.3.3.2. The formula for determining the LCR is as follows: LCRz1 = LRRz1 – Capacity Import Limitz1 OPS-12 Public Page 5-5 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 5.3 Fixed Resource Adequacy Plan (FRAP) The FRAP will identify resources that an LSE has ownership or contractual rights that will be relied upon to meet the LSE’s Planning Reserve Margin Requirement and its share of the Local Clearing Requirement (LCR) in each LRZ where the LSE has Load. The FRAP plan must be submitted via the MECT by the 7th business day of March prior to each Planning Year, and each Planning Resource must meet the qualification requirements identified in Section 4 of this Business Practice Manual document if seeking to be part of the LSE’s FRAP. MISO will review the FRAP and notify the LSE of any issues by March 15th. LSEs will have until the PRA offer window closes to resolve any issues identified by MISO. An LSE can designate its ZRCs in the FRAP up to the LSEs PRMR. ZRCs designated in the FRAP will be identified in the MECT. The ZRCs from these Planning Resources will be deducted from the available ZRC balance of that Planning Resource in the MECT. Any portion of an LSE’s PRMR not covered by the FRAP can be purchased through the PRA. 5.4 Hedges 5.4.1 Grandmother Agreements (GMA) A GMA is a financial hedge against LRZ Auction Clearing Prices (ACPs) differentials. GMA’s for existing capacity agreements hold LSEs harmless from price separation as a result of adding locational requirements to the Resource Adequacy provisions. GMAs will be acceptable only for Planning Years 2013-2014 and 2014-2015. The following criteria are required for GMA eligibility: OPS-12 LSE must have ownership or contractual rights to the resource Public Page 5-6 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Must have firm transmission service from the resource LRZ to the load LRZ Contracts and transmission services must be annual Contract must be valid through the entire Planning Year Contract must be in place prior to July 20, 2011 Hedge will expire at the end of the contract term or by May 31, 2015, whichever is first Register GMA in MECT by November 1st prior to each Planning Year. Registrations for Planning Year 2013-2014 will need to have all information populated except for the Planning Resource, Asset Owner, Local Resource Zone, and TSR /eDNR (electronic Designated Network Resource) number. Once the UCAP MW for Planning Resources are converted to ZRCs for Planning Year 2013-2014, MISO will allow Market Participants to update the Planning Resource, Asset Owner, Local Resource Zone, and TSR/eDNR number information only. Updates will need to be completed by February 1, 2013. Each GMA registration should be separate for each LRZ. A combination of capacity agreements that require the delivery of capacity throughout the Planning Year will qualify for treatment as Grandmother Agreements, provided that the agreements otherwise satisfy the criteria Intrazonal capacity transactions that become interzonal capacity transactions as a result of future revision to the LRZ boundaries during the two-year transition period will be eligible for the Grandmother Agreement hedge. Facilities under construction before July 20, 2011 that subsequently become Planning Resources OPS-12 Public Page 5-7 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Firm resources that meet Grandmother Hedge criteria may be included as part of a FRAP or offered into the annual auction. An LSE requesting a Grandmother Hedge will need to register and include documentation via the MECT by November 1st prior to the Planning Year to demonstrate their eligibility. Historical Contract Eligibility for GMA Although APRCs will cease to exist as of May 31, 2013, they can prequalify as GMAs as follows: Submit contract that MP requesting a GMA MISO will calculate annual UCAP MW of Planning Resources Market Participants will need to convert UCAP MW to Zonal Resource Credits (ZRC) o Zonal Resource Credits will have unit and LRZ specific identifiers As Market Participants transact ZRCs to fulfill contracts that meet criteria for hedge, MISO will be able to determine source of ZRCs to apply “Grandmothering” financial hedge to auction results o ZRCs transacted to fulfill existing contracts will need to have unit identifiers from aggregate deliverable generators Based on ZRCs transacted, MISO will work with the MP that qualified the GMA to determine which LRZ the Planning Resource is located If Load does not have a Grandmother Hedge with Resources that are located in an LRZ with a higher ACP, Load will pay an amount equal to the difference in the ACPs between the LRZs, times the amount of the Load. After the two year transition period for Grandmother Agreements concludes, the zonal deliverability benefit shall be distributed by the Transmission Provider such that ZDC Hedges are funded first, and then any excess credits are distributed in accordance with the Module E-1 Tariff. OPS-12 Public Page 5-8 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 5.4.2 Zonal Deliverability Charge and Hedge LSE submitting a FRAP may be subject to a ZDC. The ZDC is the difference between the ACP in the LRZ where the LSE has PRMR obligation and the ACP in the LRZ where the LSE Planning Resources are located times the volume of Planning Resources in the LRZ where their resources are located. LSE can obtain a ZDC hedge as described below as a financial protection from zonal price differences. Excess revenues collected from the PRA will be used to fund GMAs and ZDC hedges, and zonal deliverability benefit in this order. Market Participants will be eligible for a hedge against congestion in the auction if the LSE invests in new or upgraded transmission to serve the LSE’s load if located in a different LRZ. Network upgrades made for interconnection service do not qualify (NRIS/ERIS) for hedge. Also, any cost shared upgrades would not be eligible for a hedge. The participant that funds the upgrades and submits the Transmission Service request is the participant who is eligible for the hedge. However, Network upgrades associated with Transmission Service Reservation (TSR) from the new resource to load located in a different LRZ would qualify. The volume of a ZDC Hedge will be the incremental increase in the CIL that resulted from the Network Upgrades identified in the approved firm transmission service request. Market Participants must register the ZDC Hedge and provide supporting documentation in the MECT by November 1st prior to the Planning Year to demonstrate eligibility. OPS-12 Public Page 5-9 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 5.5 Planning Resource Auction (PRA) 5.5.1 Timing of Auctions. The PRA will be conducted beginning in April, which is approximately two months before the beginning of the associated Planning Year. 5.5.2 Amount of Capacity Cleared in Each Auction. Planning Resource Auction shall clear the ZRC offers in order to satisfy 100% of the PRMR for each LSE at minimum, less the amount of ZRCs associated with the Capacity Deficiency Charge and inclusive of any resources used in a FRAP, in each LRZ up to the total volume of offered ZRCs. 5.5.3 Conduct of the PRA The Auction shall be a sealed bid auction, which will determine the Auction Clearing Price (ACP) for each Local Resource Zone modeled in that Auction. The Auction shall determine the outcome of all offers accepted during the qualification process and submitted during the auction. Step 1: Compilation of Offers OPS-12 Public Page 5-10 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Offers for the Auction must be submitted in the MECT’s Submit Offer screen during the Auction window period. The offer window for the auction will be opened during the last three business days in the month of March prior to the start of the new Plan Year. Owners of jointly-owned facilities can individually offer their share of any such resources into the PRA, either as selfschedule price takers or with specific offers, or use their share of such resources as part of their FRAPs. MISO shall compile all of the offers, as follows: The MP acting on behalf of any Resource accepted in the qualification process for participation in the auction may submit an offer consisting of price and quantity pairs, indicating the minimum acceptable price and the associated quantity of ZRCs that the MP would commit to provide from the Resource in the associated modeled Local Resource Zone during the Planning Year. An offer shall be defined by the submission of up to five such pairs, each having a strictly greater price than the previous price in the submittal. Each price shall be expressed in dollars per megawatt-day, and each quantity shall be expressed in MWs. The MW/Price pairs must be monotonically increasing for price. Each offer is separately evaluated. Please see the example below. Step 2: Determination of the Outcome OPS-12 MISO shall use the ZRC offers to determine the aggregate supply curves for each MISO modeled Local Resource Zone. MISO will use the offers in conjunction with the import and export constraints, local clearing requirements, and other inputs to determine the least cost set of resources that respects the various constraints expressed as described in the Tariff. Transmission Provider will clear offers based on the needs of the LRZ and not the size of the plant (i.e. LRZ needs 50 MW, but Market Participant has a 100 MW plant only 50 MW will clear). At any non-zero clearing price, pro-rate clearing from tied bids will be applied. At a zero-clearing price, all zero-price and price-taking offers will be accepted. Public Page 5-11 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Inadequate Supply While the auction will endeavor to select ZRC offers sufficient to meet the requirements of each LRZ, it is possible that sufficient resources are not available. In such cases, the auction will clear all offered resources in the LRZ at the price approved by FERC and the LRZ would be short of Planning Resources for the Planning Year. 5.5.4 Market Monitoring All participation by resources providers is subject to the market power mitigation rules described in Module D of MISO’s Open Access Transmission Tariff. 5.5.5 Local Reliability Requirement Local Reliability Requirements for each LRZ will be determined by MISO through engineering studies based on the 0.1 days per year loss of load expectation criteria, but applied to each LRZ in isolation. From this initially determined value (the Local Reliability Requirement) will be subtracted the import capability of the LRZ from the rest of MISO’s system, resulting in the LCR value. Further details on the LCR can be found in the LOLE study. MISO will provide the LCR to LSEs by November 1st prior to the upcoming Planning Year. 5.5.6 Target Reliability Value The resultant target reliability value for each LRZ will be the greater of the system-wide value or the local clearing requirement value. The sum of these LRZ target reliability values will be the system’s target reliability value, that is, the amount of UCAP MW that must be obtained, if available, from the Auction. OPS-12 Public Page 5-12 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 5.5.7 Resource Offers Any ZRCs that were not used in the FRAP or sold to other MPs can be offered for the PRA during the Auction window period. The following business rules are applied to the PRA Offers: Offer cannot be changed or withdrawn after the Auction window is closed. Smallest Offer MW = 0.1 MW Offer Segment defined as a price-quantity pair Up to 5 Offer Segments per Planning Resource Lowest Offer price is $0.00/MW-Day Transmission Provider will clear offers based on the needs of the LRZ and not the size of the plant (i.e. LRZ needs 50 MW, but Market Participant has a 100 MW plant only 50 MW will clear) Offers will be submitted via the MECT while the Auction window is opened. At any non-zero clearing price, pro-rate clearing from tied bids will be applied At a zero-clearing price, all zero-price and price-taking offers will be accepted Only non-negative offers are accepted Self-Scheduling LSEs that “self-schedule” ZRCs by submitting offers into the PRA for the associated ZRCs with a price of $0.00 will always clear the Auction. 5.5.8 Auction Results Resource Adequacy Settlement Transmission Provider will settle the Planning Resource Auction using the following steps: 1. Determine the zonal Auction Clearing Prices for Resources and Loads within each LRZ; 2. Provide Grandmother Agreement credits equal to the zonal Auction Clearing Price differential to Load subject to Grandmother Agreements. 3. Provide Zonal Delivery Charge Hedge credits equal to the zonal Auction Clearing Price differential to Zonal Delivery Charge Hedge Load amounts. OPS-12 Public Page 5-13 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 4. Provide zonal delivery benefit credits to all remaining load in the LRZ. The zonal delivery benefit credit is determined as follows: a. Determine the remaining payments due to Resources providing service to the remaining Load in the LRZ; b. Divide (a) by the remaining Load (Load without GMA and/or ZDC hedge) in the LRZ; c. Subtract (b) from the Auction Clearing Price to determine the zonal delivery benefit credit Settlement calculations for the PRA will be conducted on a daily basis and the results will be shown under the S14 Settlements statement. Please refer to the Market Settlements BPM for further details. There are four (4) charge types under the PRA Settlement : PRA Charge Distribution of PRA Charge Zonal Deliverability Charge (ZDC) (*Only applies to the FRAP) Distribution of ZDC Capacity Deficiency Charge (Covered outside of the daily settlements) Cleared ZRCs from Diversity Contracts that are not self-scheduled or in the LSE’s FRAP will receive reduced payment based on the total number of days the external resource identified in the Diversity Contract are dedicated to MISO load when a LSE clears more ZRC in the PRA than its PRMR. The LSEs that converted UCAP MW to ZRCs will receive the auction clearing price for the entire Planning Year for those ZRCs that cleared in the PRA. OPS-12 Public Page 5-14 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 5.6 Retail and Wholesale Load Both the Retail and Wholesale Load switching between the LSEs can be tracked through the MECT Application after the start of the new planning year. As a result of the load switching , PRMR of the LSEs involved in the load switching will change. However, the EDC’s total area demand will not change due to the Retail Load switching. Similarly, the wholesale load transaction will not change the total MISO PRMR. 5.6.1.1.1 Retail Load Switching By January 15th 11:59 p.m. EST prior to start of the new Plan Year, both Electric Distribution Company (EDC) and LSEs will confirm the LSEs’ share of the EDC area Coincident Peak Forecast (i.e. PLC) and submitted in the MECT by the LSE. The LSE’s PRMR under the Retail Choice program will be initially determined based on the PLC; however, LSEs’ PRMR will change during the Planning year when the load from one LSE is switched to another LSE within the EDC area. 5.6.1.1.2 Non-Retail Load Switching For the case of the wholesale Load switching, the amount of the PRMR transacted via the wholesale load transaction process will transfer the PRMR of the current LSE to the new LSE starting with the effective date specified in the Wholesale transaction. The transaction must be confirmed in the MECT before the start of the effective date. 5.6.1.1.3 Default Method The preferred default method is based on the PLC value of each retail customer, which is based on the customer’s demand at the time of the Transmission Provider’s peak demand during the OPS-12 Public Page 5-15 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Summer prior to the Planning Year. The PLCs in total will be set equal to the forecast provided by the EDC. Specific methods used by the EDC to calculate each customer’s PLC must be provided to both MISO and LSEs no later than December 15th on the year prior to upcoming Planning Year. Then LSEs will have until January 15th to verify the EDC provided data and submit the aggregated total in the MECT. In the event that no data is available to use for the default method described above, a “daily peak load” default methodology will be used. The daily capacity charges relating to the PRMR will be allocated based on the historical share of the Summer peak load from previous Planning Year. 5.6.1.1.4 Retail Load Switching under the Default Method The Retail Load screen in the MECT is provided for EDCs in Retail Choice states utilizing the Default Method to track the LSE’s day-to-day migration of loads at the Asset Owner (AO) level. Using the daily retail load switching information in the MECT, MISO Settlements calculates the LSE’s new PRMR. The LSEs’ PRMR are subject to resettlement calculations based on the resubmission of the load switching information. For LSEs using the backup Default Method, their load switching will be determined based on the daily Load served by each LSE within the EDC’s area for the peak hour of the Transmission Provider’s region which the EDC submitted to the MISO’s Settlements system. The backup Default Method will be employed until the permanent solution is in place. The daily retail load switching information includes: Name of the EDC Zone Name of the LRZ OPS-12 Public Page 5-16 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Effective Date of Retail load switching Name of AO(s) AO’s new Retail MW (with 3 decimal points) 5.6.1.1.5 Wholesale Load Switching Wholesale Load obligation can be switched from one LSE to another using the Wholesale transaction screen in the MECT during the Planning Year. When wholesale Load switching occurs, the daily capacity charges of wholesale Load will be transferred from the current LSE to the new LSE. The PRMR for affected LSEs will be decreased or increased, as appropriate, by the amount of the wholesale load plus the PRM. Procedures for billing, settlement, and credit requirements will be as specified in the appropriate BPMs. LSEs with wholesale contracts that change during the Planning Year enter a wholesale Load switching contract representing PRMR in the MECT. 5.6.1.1.6 Distribution of Capacity Deficiency Charges Revenues The Transmission Provider will impose a capacity deficiency charge on an LSE that has not demonstrated, at the close of the Planning Resource Auction, to the Transmission Provider, through the MECT, that it has arranged sufficient zonal capacity resources to meets it PRMR. The annual capacity deficiency charge will be calculated as follows: The CONE value for the LRZ where the LSE has not arranged through the MECT sufficient ZRCs will be multiplied by 2.748 times the number of Zonal Resource Credits that the LSE is deficient. The capacity deficiency charge will be assessed to a capacity deficient LSE on the first business day after the results of the Planning Resource Auction have been published. b. Distribution of Capacity Charge Revenues: Capacity Deficiency Charge revenues received by the Transmission Provider will be distributed to LSEs on a pro rata basis, based upon MW of annual peak load of LSEs that have met their RAR during the Planning Year. If the LRZ where OPS-12 Public Page 5-17 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 the LSE incurred Capacity Deficiency Charges failed to meet its LCR, then Capacity Deficiency Charge revenues will be allocated solely to LSEs that have met their RAR in the applicable LRZ. Otherwise, Capacity Deficiency Charge revenues will be allocated to all LSEs that have met their RAR in the Transmission Provider footprint. 5.6.1.1.7 Settlements of Wholesale and Retail Switching All confirmed Information submitted by the deadline (per Market Settlements BPM) will be transferred to Market Settlements for the settlements calculation. MISO will perform the following calculation using the LSE’s daily switching information submitted in the MECT. MISO will perform the following calculation using the AO’s daily switching information submitted to the LTS. MISO calculates each AO’s % ownerships of the demands at the EDC Zone. MISO calculates each AO’s daily PRMR based on the retail load switching information. MISO calculates the charges and credits by applying the Auction Clearing Price (ACP) to the new daily PRMR for each AO. At the end of each billing cycle (i.e. Weekly), MISO will sum up the daily charges for each LSE based on the daily Switching information in the MECT for the weekly invoicing. The Market Settlements BPM provides more information regarding this process. MISO will settle the Retail Load Switching (RLS) MW by charging the Planning Resource Auction Price for the applicable LRZ for each day to MPs based on the RLS data submitted for both Initial or Final submission. The invoice (charge) for the Initial RLS data will be available in the Market Portal in the S7 Settlement Statements. The invoice (charge) for the final RLS data will be available in the S55 Settlement Statements. Please refer to Settlements BPM for further details. Calculation Methodology will be the retail PLCs of retail customers within an EDC. OPS-12 Public Page 5-18 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 6. Performance Requirements 6.1 Must Offer Requirement and Monitoring The must offer requirement is established by converting a UCAP MW to ZRC and applying it to the Installed Capacity of a Generation Resource, and not to the UCAP rating of the Generation Resource. Installed Capacity refers to the amount of ZRCs divided by (1 – XEFORd) of the Capacity Resource. In the event of a retirement or mothballing of a Generation Resource LRZ zone and have not been used to satisfy Planning Reserve Margin Requirements elsewhere (no double counting). LSEs opting to substitute ZRCs for Capacity Resources that have been or will be retired, mothballed and not operational, suspended, should notify a member of the Resource Adequacy team in writing at least 60 days prior to such change. The LSE should include the name of the Capacity Resource being retired or mothballed, date of retirement or mothball, and list Resource(s) that will meet the must offer requirements. On a daily basis, MISO will monitor whether the Offers submitted by the Asset Owner of each Capacity Resource in the Day-Ahead Energy and Operating Reserve Market and first post Day-Ahead RAC process meet the mustoffer requirements for the amount of Installed Capacity. MISO will compare the difference between the Emergency default Maximum Limit (MW) or scheduled maximum (MW) offer and the must-offer requirement (MW) for each hour of each day. If the Offers for Day Ahead and first post Day-Ahead RAC are less than the must-offer requirement, then MISO will compare the difference to derates in MISO’s Outage Scheduler (CROW) for such resources. Outages, derates and Offers will be captured based on the information provided at both the DA Market close and first post Day-Ahead RAC close. DA Market close and first post Day-Ahead RAC close times are addressed in the Energy and Operating Reserve Markets BPM. MISO will apply a tolerance threshold to all resources based on the must offer requirement listed in the MECT under ZRC Available Balance. The threshold will be applied at the CPNode level except for OPS-12 Public Page 6-1 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 those resources noted otherwise in the appropriate sub-sections in section 4 of this BPM. The thresholds were developed to recognize that data entry errors could occur when providing derate volumes through MISO’s Outage Scheduler (CROW). They do not relieve the MP of the obligation to meet the must-offer requirement for the tolerance threshold volume will be applied at the CPNode level except for those resources noted otherwise in this BPM. The thresholds are as follows: The lesser of 10 MW or 10% for Capacity Resources greater than or equal to 50 MW The greater of 1 MW or 10% for Capacity Resources less than 50 MW Offered MW (Emergency Max) >=must offer requirement less Threshold (excluding Capacity Resources that submit Intermittent Forecasts that have been accepted by MISO) If the amount of the derate in CROW plus the appropriate threshold is greater than or equal to the above mentioned difference including the appropriate threshold is documented in the MISO Outage Scheduler (CROW) as a derate for such hours, then the MP will have passed the mustoffer monitoring check. If the difference is not documented as a derate or full outage, then the MP will not pass monitoring check. MISO will notify MPs through a report published on the MECT portal of their must offer status. If a Market Participant believes there is a discrepancy in their must-offer report, the Market Participant can notify MISO via email to Resource Adequacy personnel of the discrepancy and submit supporting documentation. Outage information should include all revisions from the outage submission to the completion of the outage. MISO will review the information submitted and notify the Market Participant within seven (7) business days via email of the outcome of the review. The IMM also has access to the reports published on the MECT portal and may contact Market Participants directly on any compliance issues. Section 69A.5 of the Tariff outlines the process once an Asset Owner is found to be in violation of the Must-Offer provisions. OPS-12 Public Page 6-2 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 6.2 Ongoing Calculation of CONE and Net CONE MISO will work with the Independent Market Monitor (IMM) to recalculate CONE by August 1st and Net CONE annually by September 1 of each year, for Planning Years after the initial Planning Year. In calculating the CONE value, the IMM and MISO will consider the following factors: physical factors: type of resource, location, costs for fuel financial factors: debt/equity ratio, cost of capital, ROE, taxes, interest, insurance other factors: permitting, environmental, Operating and Maintenance costs, etc. MISO and the IMM will not consider anticipated net revenues from the sale of capacity, Energy, or Ancillary Services as factors in the annual recalculation of the CONE. MISO shall annually determine and file revised Net CONE values for a Combined Cycle Generation Unit (CC) and a Combustion Turbine Generation Unit (CT) for each LRZ with the Commission no later than September 1st of each year beginning on September 1, 2012, to become effective for the following Planning Year. The Net CONE determination for an LRZ will be based upon the localized, levelized annual embedded costs of the appropriate facility (CC or CT) in an LRZ, net of the expected infra marginal rents from participation in the Energy and Ancillary Services markets. The offset from the expected value of infra marginal rents will be calculated based on a statistical process using the following data: (i) the most recent three (3) years of calendar year data of Energy and Operating Reserves Market revenues from representative CC or CT resources participating in MISO’s market; (ii) the producer surplus achieved from these same resources; and (iii) adjustments for weather normalization, adjustments for forecasted fuel prices and adjustments for resource availability for the Planning Year. OPS-12 Public Page 6-3 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Once the IMM and MISO have calculated the CONE and the Net CONE, MISO will make a filing with the Commission under Section 205 of the Federal Power Act seeking approval from the Commission for the re-calculated CONE and Net CONE. The table below contains the CONE values for each Planning Year: Planning Year 2009 - 2010 2010 - 2011 2011 - 2012 6.3 CONE Value $/MW 80,000 90,000 95,000 Replacement Resources Any Planning Resource that cleared in the Planning Resource Auction that is being retired or mothballed during the Planning Year for which it cleared should be replaced with a Planning Resource located in the same Local Resource Zone. The Planning Resource replacing the mothballed or retired unit must have available UCAP MW to convert to ZRCs. All replacements will be done in the MECT by the Market Participant who has the must offer requirement. MPs must notify Resource Adequacy (7) days prior to such replacement occurring. OPS-12 Public Page 6-4 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 6.4 LMR performance 6.4.1 BTMG Performance When a BTMG that cleared in the PRA fails to perform during emergency conditions when called on by MISO or the LBA, penalties are calculated for each hour in which a BTMG fails to respond in an amount greater than or equal to the target level of generation increase as the sum of: (1) the product of (a) the amount of increased generation not achieved and (b) the LMP at the CPNode associated with the BTMG; and (2) applicable Revenue Sufficiency Guarantee (“RSG”) Charges. The amount of increased generation not achieved for BTMG is equal to the greater of: (1) the difference between (a) the target level of generation increase and (b) the actual increased generation; and (2) zero. The applicable RSG Charges are equal to the product of: (1) the difference between (a) the target level of increased generation and (b) the actual increased generation; and (2) the RSG First Pass Distribution rate for the applicable Hour. The revenues from charges resulting from LMRs that fail to respond in an amount greater than or equal to the Scheduling Instructions shall be allocated, pro rata, to MPs representing LSEs in the LBA area(s) that experienced the Emergency, on a load ratio share basis. For any situation where a BTMG does not increase generation, including those circumstances where the resource is claimed to be unavailable as a result of maintenance requirements or for reasons of Force Majeure, MISO shall initiate an investigation into the cause of the LMR not being available when called upon, and may, if deemed appropriate, disqualify that resource from ACP payments for that Planning Year. The BTMG will be called but not required to respond if the Emergency call is outside the resource’s registration limitations (i.e. less than the registered time to respond, the event lasts longer than the registered duration, is made outside the Summer period or the resource has reached its registered number of deployments). OPS-12 Public Page 6-5 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 In the event the same BTMG is not sufficiently responsive on a second occasion during a Planning Year (with a separation period of at least 24 hours) when called upon by MISO to increase generation, except for a validated circumstance of maintenance requirements, for reasons of Force Majeure or other acceptable reasons defined in the tariff or this BPM, the LSE that has cleared ZRCs from an accredited LMR in the PRA will be subject to the penalties described herein (if that LMR fails to increase generation to the level instructed). Such BTMG shall be assessed the same penalty as indicated above, and the BTMG will no longer be eligible to receive ACP payments for the current Planning Year and for the next Planning Year. If, in review of the BTMG’s measurement and verification data following an Emergency, MISO determines that the MP has committed fraud to receive excess payments or avoid penalties, MISO will have the right to ban the MP or its customers from participation in the wholesale electricity markets, as well as, pursue other legal options at the sole discretion of MISO. 6.4.2 DR Performance If a DR that cleared in the PRA fails to perform during an Emergency when called on to reduce Demand by MISO or the LBA, penalties will be calculated for each hour in which a DR fails to respond in an amount greater than or equal to the target level of Load reduction as the sum of: (1) the product of (a) the amount of Load reduction not achieved and (b) the LMP at the CPNode associated with the DR; and (2) applicable RSG Charges. The amount of Load reduction not achieved for DRs is equal to the greater of: (1) the difference between (a) the target level of Load reduction and (b) the actual Load reduction; and (2) zero. The RSG Charges are equal to the product of: (1) the difference between (a) the target level of Load reduction and (b) the actual Load reduction; and (2) the RSG First Pass Distribution rate for the applicable Hour. OPS-12 Public Page 6-6 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 The revenues from charges resulting from DRs that fail to respond in an amount greater than or equal to the Scheduling Instructions shall be allocated, pro rata, to MPs representing LSEs in the LBA area(s) that experienced the Emergency, on a load ratio share basis. For any situation where a DR does not respond in an amount greater than or equal to the target level of Load reduction, including those circumstances where the resource is unavailable for maintenance reasons or Force Majeure, MISO shall initiate an investigation into the cause of the LMR not being available when called upon, and may, if deemed appropriate, disqualify that resource from ACP payments for that Planning Year. The DR will be called but not required to respond if the Emergency call is outside the resource’s registration limitations (i.e. less than the registered time to respond, the event lasts longer than the registered duration, is made outside the Summer period or the resource has reached its registered number of deployments). In the event the same DR is not sufficiently responsive on a second occasion during a Planning Year (with a separation period of at least 24 hours) when called upon by MISO to reduce Load for a DR or increase generation for a BTMG, except for a validated circumstance of maintenance requirements or for reasons of Force Majeure, the LSE that cleared ZRCs in the PRA from an accredited LMR or netted accredited DRs against its Demand forecast will be subject to the penalties described herein (if that DR fails to respond in an amount greater than or equal to the target level of a Demand Resource Load or to the firm service level). The MP using the DR shall be assessed the same penalty as indicated above, and the DR will no longer be eligible to receive ACP payments for the remainder of the current Planning Year and for the next Planning Year (s) unless the DR is unavailable due to for maintenance reasons, Force Majeure or other acceptable reasons as outlined in the Tariff or this BPM. OPS-12 Public Page 6-7 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 7. Testing Procedures and Requirements 7.1 Generator Real Power Verification Testing Procedures MISO has developed generator test standards as documented in Appendix J of this BPM will apply for Planning Years 3 and beyond. 7.2 Midwest Reliability Organization - MRO The MRO Generator Testing Requirements can be found at: http://www.midwestreliability.org/03_reliability/06_gtrtf/2007/Documents/MRO%20Generator%2 0Testing%20Requirements%20Rev%200b.pdf See MRO’s website for testing requirements 7.3 Reliability First Corporation - RFC The Generator Verification Data Reporting standard drafting team is developing an RFC standard on generator verification to be approved by the Board of Directors. Until that standard is approved, each generator owner remains responsible for testing or verifying the capacity ratings of their generators in accordance with its legacy region's requirements. Generator owners in the former MAIN and ECAR regions can find reporting forms below that are available to download and complete. Completed reporting forms can be submitted to Paul Kure (paul.kure@rfirst.org ) at the ReliabilityFirst office. Former MAAC members will continue to submit their generator test/verification data via the PJM eGADS system. ECAR Generator Forms (DOC) | MAIN Generator Forms (XLS) The ECAR Generator Testing Requirements can be found on Reliability First’s website. http://www.rfirst.org/Documents/Standards/Approved/Legacy/ECAR.pdf OPS-12 Public Page 7-1 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 The MAIN Generator Testing Requirements can be found on Reliability First’s website. : http://www.rfirst.org/Documents/Standards/Approved/Legacy/MAIN%20Bylaws%20and%20Gui des.pdf The “Draft” RFC Generator Testing Requirements can be found at: on Reliability First’s website. http://rfc.rsvp.midwestreliability.org/rfc_rsvp/action/PubMainAction?type=Detail&id=16 7.4 SERC Reliability Corporation – SERC The SERC Generator Testing Requirements can be found on SERC’s website. http://www.serc1.org/Documents/SERC%20Supplements/Planning/Active%20Supplements%20 (Wholly%20or%20Partially%20Reference%20Current%20NERC%20Reliability%20Standards)/ Verification%20of%20Gen%20Real%20and%20Reactive%20Power%20Cap%20SERC%20Sup plement%20(8-11-06).pdf 7.5 North American Electric Reliability Corporation – NERC, MOD 24 The NERC Verification of Generator Gross and Net Real Power Capability Standard, “MOD – 024 – 1 can be found on NERC’s website. http://www.nerc.com/~filez/standards/Reliability_Standards_Regulatory_Approved.html OPS-12 Public Page 7-2 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-1-2012 8. Appendices Appendix A – Wind Capacity Credit The basic goal is to estimate the reliable output of wind as a percentage of the installed capacity, for the MISO System and by CPnode. This involves the following data. Driving Data for Wind Capacity Credit The hourly load and the hourly wind output for 8,760 hours. This concurrent load and wind data, along with the normal complement of generator data in an LOLE simulation, is essential for determining the system wide Effective Load Carrying Capacity (ELCC) of the wind resources. MISO tracks the hourly wind output for the top 8 daily peak hours, by MISO total and individual wind CPnodes. The system wide and CPnode data is used to allocate the system wide Effective Load Carrying Capacity (ELCC) among individual CPnodes. MISO tracks the hourly amounts by which individual wind CPnodes are dispatched downward as part of the Dispatchable Intermittent Resources (DIR) activity. Similarly, MISO estimates the MW that CPnodes may have been curtailed. OPS-12 Public Page 8-1 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-1-2012 Since 2009 MISO has embarked on a process to determine the capacity value for the increasing fleet of wind generation in the system. The MISO process as developed and vetted through the MISO stakeholder community consists of a two-step method. The first-step utilizes a probabilistic approach to calculate the MISO system-wide Effective Load Carrying Capability (ELCC) value for all wind resources in the MISO footprint. The second-step employs a deterministic approach using specific information about the location of each wind resource ‘period metric’ to allocate the single system-wide ELCC value across all wind CPnodes in the MISO system, to determine a wind capacity credit for each wind node. As the geographical distance between wind generation increases, the correlation in the wind output decreases. This leads to a higher average output from wind for a more geographically diverse set of wind plants, relative to a closely clustered group of wind plants. Due to the increasing diversity and the inter-annual variability of wind generation over time, the process needs to be repeated annually to incorporate the most recent historical performance of wind resources into the analysis. So for each upcoming planning year the wind capacity credit values in MISO are updated to account for both the stochastic nature of wind generation and the ever increasing integration of new resources into the system. The sections of this write-up and current results illustrated here are broken down to describe the details of the two-step method adopted by MISO for determining wind capacity credit for the 2012 planning year. OPS-12 WAS:150021.1 Public Page 8-2 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-1-2012 Wind Output Correlation vs. Distance Between Wind Sites Step-1: MISO System-Wide Wind ELCC Study Probabilistic Analytical Approach The probabilistic measure of load not being served is known as Loss of Load Probability (LOLP) and when this probability is summed over a time frame, e.g. one year; it is known as Loss of Load Expectation (LOLE). The accepted industry standard for what has been considered a reliable system has been the “Less than 1 Day in 10 Years” criteria for LOLE. This measure is often expressed as 0.1 days/year, as that is often the time period (1 year) over which the LOLE index is calculated. Effective Load Carrying Capability (ELCC) is defined as the amount of incremental load a resource, such as wind, can dependably and reliably serve, while considering the probabilistic nature of generation shortfalls and random forced outages as driving factors to load not being served. Using ELCC in the determination of capacity value for generation resources has been around for nearly half a century. In 1966, Garver demonstrated the use of loss-of-load probability mathematics in the calculation of ELCC [1]. To measure ELCC of a particular resource, the reliability effects need to be isolated for the resource in question, from those of all the other sources. This is accomplished by calculating OPS-12 WAS:150021.1 Public Page 8-3 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-1-2012 the LOLE of two different cases: one “with” and one “without” the resource. Inherently, the case “with” the resource should be more reliable and consequently have fewer days per year of expected loss of load (smaller LOLE). The new resource in the example shown in Fig. 3 made the system 0.07 days/year more reliable, but there is another way to express the reliability contribution of the new resource besides the change in LOLE. This way requires establishing a common baseline reliability level and then adjusting the load in each case “With” and “Without” the new resource to this common LOLE level. A common baseline that is chosen is the industry accepted reliability standard of 1 Day in 10 Years (0.1 days/year) LOLE criteria. Example System “With” & “Without” New Base System LOLE = 0.15 days/year (or 1½ days in 10 years) + New Base System Resource LOLE = 0.08 days/year (or 0.8 days in 10 years) Figure 3 Example System “With” and “Without” New Resource With each case being at the same reliability level, as shown in Fig. 4, the only difference between the two cases is that the load was adjusted. This difference is the amount of ELCC expressed in load or megawatts, which is 300 MW (100 – -200) for the new resource in this example. Sometimes this number is divided by the nameplate rating of the new resource and then expressed in percentage (%) form. The new resource in the ELCC example Fig. 4 has an ELCC of 30% of the resource nameplate. OPS-12 WAS:150021.1 Public Page 8-4 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-1-2012 ELCC Example System at the same LOLE Decreased Base System -200 MW LOLE = 0.1 days/year (or 1 day in 10 years) + New Load Base System Resource 1000 MW +100 MW LOLE = 0.1 days/year (or 1 day in 10 years) Nameplate Figure 4 ELCC Example System at the same LOLE The same methodology illustrated in the simple example of Fig. 4 was utilized as the analytical approach for the determination of the system-wide ELCC of the wind resource in the much more complex MISO system. For each historic year studied there were two types of cases analyzed, ones with and ones without the wind resources. Each case was adjusted to the same common baseline LOLE and the ELCC was measured off those load adjustments. Using ELCC is the preferred method of calculation for determining the capacity value of wind [2]. LOLE Model Inputs & Assumptions To apply the ELCC calculation methodology MISO uses the Multi-Area Reliability Simulation (MARS) program by GE Energy to calculate LOLE values with and without the wind resource modeled. This model consisted of three major inputs: Generator Forced Outage Rates (FOR) Actual Historic Hourly Load Values Actual Historic Hourly Wind Output Values Forced outage rates are used for the conventional type of units in the LOLE model. These FOR are calculated from the Generator Availability Data System (GADS) that MISO uses to collect OPS-12 WAS:150021.1 Public Page 8-5 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-1-2012 historic operation performance data for all conventional types units in the MISO system as well as the capacity throughout the country. To incorporate historical information the actual 2005-2011 historical hourly concurrent load and wind output at the wind CPNodes is used to calculate the historic ELCC values for the wind generation in the MISO on a system-wide basis. The last two columns in Table I illustrate the ELCC results for the 7-years of MISO historic data. MISO System Wide ELCC Results MISO calculated ELCC percentage results for historic years 2005 through 2011 and at multiple scenarios of penetration levels, corresponding to 10 GW, 20 GW and 30 GW of installed wind capacity. This creates an ELCC penetration characteristic for each year, as illustrated by the different curves in Fig. 5. The initial left most data point for each curve is at the lowest penetration point on each characteristic curve and represents the actual annual ELCC for that year; and the values are shown in the right column in Table I. The values along each year’s characteristic curve at the higher penetration levels reflect what that year’s wind resource would have as an ELCC if more capacity had been installed in that year, over the same MISO footprint. The high end 30 GW level of penetration is an estimate of the amount of wind generation that could result in MISO, as the Load Serving Entities (LSE) collectively meet renewable resource mandates of the various MISO States The end of a 2nd Quarter is the convention used to set the capacity going into the next planning year. The penetration level at the end of the 2nd Quarter 2011 was 9.7%. Specifically as a percentage, the 2011 penetration level is the 2nd Quarter 9,996 MW in column-4 of Table 1 divided by the 102,804 MW peak load in column-1. The vertical line in Fig. 5 illustrates where the most recent historical 9.7% penetration level intersects each year’s ELCC characteristic curve. The average of these seven intersect values is the 14.7% system wide ELCC assigned for the upcoming planning year 2012. TABLE 1 MISO Historical Wind ELCC Values OPS-12 WAS:150021.1 Public Page 8-6 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-1-2012 MISO Peak Load Year (MW) Registered Historical System- System- Wind Max Wind Wide Wide Capacity Penetration ELCC ELCC (MW) (%) (MW) (%) 2005 109,473 908 0.8% 152 16.7% 2006 113,095 1,251 1.1% 495 39.6% 2007 101,800 2,065 2.0% 57 2.8% 2008 96,321 3,086 3.2% 395 12.8% 2009 94,185 5,636 6.0% 173 3.1% 2010 107,171 8,179 7.6% 1,548 18.9% 2011 102,804 9,996 9.7% 3,007 30.1% The ELCC characteristic of each year can be represented by a trend line equation that has an R2 coefficient of no less than 0.9996. This is the basis for achieving accuracy with sparse or few years of data. Alternative attempts to directly find a composite suitable single-trend-line curve to represent the aggregate 28 ELCC characteristic points of all seven years, met with poor R2 coefficients in the range of 0.04 to 0.11. Step-2: Wind Capacity Credit by CPnode Calculation Deterministic Analytical Technique Since there are many wind CPnodes throughout the MISO system (143 in 2011), a deterministic approach involving an historic-period metric is used to allocate the single system-wide ELCC value of wind to all the registered wind CPnodes. While evaluation of all CPnodes captures the benefit of the geographic diversity, it is important to assign the capacity credit of wind at the individual CPnode locations, because in the MISO market the location relates to deliverability due to possible congestion on the transmission system. Also, in a market it is important to convey the correct incentive signal regarding where wind resources are relatively more effective. The location and relative performance is a valuable input in determining the tradeoffs OPS-12 WAS:150021.1 Public Page 8-7 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-1-2012 between constructing wind facilities in high capacity factor locations, that in the case of the MISO are located in more remote locations far from load centers, and requiring more transmission investment versus locating wind generating facilities at less effective wind resource locations that may require less transmission build-out. The system-wide wind ELCC value of 14.7% times the 2011 installed registered wind capacity of 9,996 MW results in 1,469 MW of system-wide capacity. The 1,469 MW is then allocated to the 143 different CPnodes in the MISO system. The historic output has been tracked for each wind CPnode over the top 8 daily peak hours for each year 2005 through 2011. The average capacity factor for each CPnode during all 56 (8-hours x 7-years) historical daily peak hours is called the “PKmetricCPnode” for that CPnode. The capacity factor over those 56 hours and the installed capacity at each CPnode, are the basis for allocating the 1,469 MW of capacity to the 143 CPnodes. MISO has developed business practice Manual for the handling of new wind CPnodes that do not have historic output data, and for CPnodes with less than 7-years of data. Tracking the top 8 daily peak hours in a year is sufficient to capture the peak load times that contribute to the annual LOLE of 0.1 days/year. For example, in the LOLE run for year 2011, all of the 0.1 days/year LOLE occurred in the month of July, but only 4 of the top 8 daily peaks occurred in the month of July. Therefore, no more than 4 of the top daily peaks contributed to the LOLE. Other years have LOLE contributions due to more than 4 days, however 8 days was found sufficient to capture the correlation between wind output and peak load times in all cases. If many more years of historical data were available, one could simply utilize the single peak hour from each year as the basis for determining the PKmetricCPnode over multiple years. Wind CPnode Equations Registered Maximum (RMax) is the MISO market term for the installed capacity of a resource. The relationship of the wind capacity rating to a CPnode’s installed capacity value and Capacity Credit percent is expressed as: OPS-12 WAS:150021.1 Wind Capacity Rating RMax CPnode n CPnode n Capacity Credit % CPnode Public n (1) Page 8-8 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-1-2012 Where RMaxCPnode n = Registered Maximum installed capacity of the wind facility at the CPnode n. The right most term in (1), the (Capacity Credit %)CPnode n can be replaced by the expression (2) : K PKmetric CPnode n % (2) Where “K” for Year 2011 was found by obtaining the PKmetric at each CPnode over the 7 year period, and solving expression (3): K 143 ELCC RMax CPnoden PKmetric CPnoden (3) 1 This results in the sum of the MW ratings calculated for the CPnodes equal to the system wide ELCC 1,479 MW. The values in (3) are: ELCC = 1,469 MW ∑ RMaxCPnode n x PKmetricCPnode n = 1,803 MW Therefore: K = 0.8148 = 1,469 / 1,803 Wind CPnode Capacity Credit Results & Examples The individual PKmetric’sCPnode of the CPnodes ranged from zero to 39.9%. The individual Capacity Credit percent for CPnodes therefore ranged from zero to 32.5%, by applying expression (2) Example 1) For the best performing CPnode through 2011 data, the 39.89% PKmetric drives the capacity credit equal to: 32.5% = 39.9% x 0.8148, and therefore 32.5% times that CPnode’s RMax would equal the Unforced Capacity (UCAP) rating for the best performing CPnode. Example 2) For the CPnode nearest the nominal 14.7% capacity credit through 2011 data, the 18.2% PKmetric drives the capacity credit equal to: OPS-12 WAS:150021.1 Public Page 8-9 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-1-2012 14.8% = 18.2% x 0.8148, and therefore 14.8% times that CPnode’s RMax would equal the UCAP rating for that CPnode. The MISO capacity credit method uses actual historical power output as a basis for setting the capacity rating of wind resources. While, MISO is currently limited to applying seven years of historical power outputs from the wind resources; by applying the developed ELCC and merging techniques the results are converging and are reflective as if one had more years of historical data available for the process. Fig. 9 illustrates the method over a range of limited data results. The left most point on the x-axis is the system wide result while utilizing only one year of data, the second point represents having two years of historical data available for the process. Progressively, the seventh point illustrates where MISO is currently at with seven years of data, and a projection sensitive to penetration is shown. As data from each new successive year becomes available, the subsequent capacity credit for successive years is expected to stabilize, and be more exclusively driven by penetration. While the process discussed here represents a consistent and repeatable way to calculate the MISO market needs, MISO will continue to track and consider adjustments that may be required to deal with further aspects of common mode failure of wind generation. The MISO believes that the capacity credit for wind will be near 10% as the system approaches 25,000 to 30,000 MW of installed wind generation. Wind Capacity Credit Method 30% 25% 14.7% System‐Wide Wind ELCC Value 20% 10 GW Penetration 15% 20 GW Penetration 30 GW Penetration 10% If Applied to Past 5% Capacity Credit Projection 0% 0% 10% 20% 30% Penetration OPS-12 WAS:150021.1 Public Page 8-10 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-1-2012 Wind Capacity Credit Method 30% 25% 14.7% System‐Wide Wind ELCC Value 20% 10 GW Penetration 15% 20 GW Penetration 30 GW Penetration 10% If Applied to Past 5% Capacity Credit Projection 0% 0% 10% 20% 30% Penetration Figure 9 Applying Capacity Credit Method Starting with 2005 data 8.1.1.1.1 [1] [2] References Garver, L.L.; , "Effective Load Carrying Capability of Generating Units," Power Apparatus and Systems, IEEE Transactions on , vol.PAS-85, no.8, pp.910-919, Aug. 1966 Keane, A.; Milligan, M.; Dent, C.J.; Hasche, B.; D'Annunzio, C.; Dragoon, K.; Holttinen, H.; Samaan, N.; Soder, L.; O'Malley, M.; , "Capacity Value of Wind Power," Power Systems, IEEE Transactions on , vol.26, no.2, pp.564-572, May 2011 OPS-12 WAS:150021.1 Public Page 8-11 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Appendix B – Generator Testing and XEFORd details (OMC Codes) The following chart lists the GADS Cause Codes applicable to reporting outages to MISO: GADS Cause Codes Outside Plant Management Control (OMC) (As of January 1st, 2006) 3600 Switchyard transformers and associated cooling systems – external 3611 Switchyard circuit breakers – external 3612 Switchyard system protection devices – external 3619 Other Switchyard equipment – external 3710 Transmission line (connected to powerhouse switchyard to 1st Substation) 3720 Transmission equipment at the 1st Substation (see code 9300 if applicable) 3730 Transmission equipment beyond the 1st Substation (see code 9300 if applicable) 9000 Flood 9010 Fire, not related to a specific component 9020 Lightning 9025 Geomagnetic disturbance 9030 Earthquake 9035 Hurricane 9036 Storms (ice, snow, etc) 9040 Other catastrophe 9130 Lack of fuel (water from rivers or lakes, coal mines, gas lines, etc) where the operator is not in control of contracts, supply lines, or delivery of fuels OPS-12 Public Page 8-12 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 9150 Labor strikes company-wide problems or strikes outside the company’s jurisdiction such as manufacturers (delaying repairs) or transportation (fuel supply) problems 9250 Low Btu coal 9300 Transmission system problems other than catastrophes (do not include switchyard problems in this category; see codes 3600 to 3629, 3720 to 3730) 9320 Other miscellaneous external problems 9500 Regulatory (nuclear) proceedings and hearings 0 regulatory agency initiative 9502 Regulatory (nuclear) proceedings and hearings 0 intervener initiated 9504 Regulatory (environmental) proceedings and hearings 0 regulatory agency initiated 9506 Regulatory (environmental) proceedings and hearings 0 intervener initiated 9510 Plant modifications strictly for compliance with new or changed regulatory requirements (scrubbers, cooling towers, etc) 9590 miscellaneous regulatory (this code is primarily intended for use with event contribution code 2 to indicate that a regulatory-related factor contributed to the primary cause of the event) Outside Management Control (OMC) Outages There are outages from outside sources that result in generating units restricted in generating capabilities or in full outages. Such outages include (but are not limited to) ice storms, hurricanes, tornados, poor fuels, interruption of fuel supplies, etc. A list of GADS causes and their cause codes for OMC events are listed on the following page. MISO has generated this list based on what PJM has adopted and these OMC codes will be the only codes accepted by MISO for GADS purposes. For more detailed information regarding OMC outages and codes please refer to Appendix K of the NERC GADS Data Reporting Instructions. OPS-12 Public Page 8-13 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Appendix C – Registration of Energy Efficiency Resources Registration Requirements Plan Year ENERGY EFFICIENCY RESOURCE Name Description Energy Efficiency Resource Explanation Select the Planning Year you are registering your ENERGY EFFICIENCY RESOURCE. Enter Name of the ENERGY EFFICIENCY RESOURCE. Registering Asset Owner Local Resource Zone Local Balancing Area (LBA) Load Zone CPNode Program Information Program Inception Year Program Name Energy Efficiency Available at MISO Peak Demand Reduction/Allocation Capability Added Each Plan Year Accreditation Primary Contact Name (24 x7) Primary Contact Phone (24x7) Comments OPS-12 Enter type of resources and additional names and sizes if registering more than one unit. Enter the name of the entity that owns or has rights to this asset. Select the Local Resource Zone where this ENERGY EFFICIENCY RESOURCE is located Select the LBA where this ENERGY EFFICIENCY RESOURCE asset is located. Enter the CPNode where the ENERGY EFFICIENCY RESOURCE asset is located. Indicate if this is a new program or previously registered program Select year program began Name of program that is being registered Enter MW value of program at MISO Peak Enter MW value of program being netted and/or used as a Planning Resource Enter MW difference in program from the Inception Year Attach supporting documentation Enter name of person who should be contacted with questions on this registration. Enter phone number of person who should be contacted with questions on this registration. Submit any comments for this registration Public Page 8-14 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Appendix D – Registration of DRs Demand Resource (DR) Registration Requirements Plan Year DR Name Description Registering Asset Owner Local Resource Zone Local Balancing Area (LBA) Load Zone CPNode Registered DRR DRR CPNode Accreditation NERC Reporting City (where the LMR is located) County (where the LMR is located) State (where the LMR is located) Load Control Method EDR? Emergency Demand Resource Curtail to Peak Firm Service Level Monthly peak firm service levels Plan Year Interruptions and Run Time M&V protocol to be applied to this DR OPS-12 Explanation Select the Planning Year you are registering your DR. Enter Name of the DR. Enter type of resources and additional names and sizes if registering more than one unit. Enter the name of the entity that owns or has rights to this asset. Select the Local Resource Zone where this DR is located Select the LBA where this DR asset is located. Enter the CPNode where the DR asset is located. Indicate if this resource is registered as a DRR Select the name of the DRR CPNode that is registered Attach supporting documentation Provide 24 monthly MW levels associated with the installed capacity of the DR each month. Monthly values shall be provided for the first two years from the Effective Start Date. Provide 16 seasonal (Summer and Winter) MW levels associated with the installed capacity of the DR for each season. Seasonal values shall be provided beyond the 2 year monthly window. Enter the city where the DR is located. Enter the county where the DR is located. Enter the state where the DR is located. Select if load is direct control or interruptible load Check box if DR registered as an EDR Select the registered name of the EDR. Check box if DR can curtail to firm service level Enter monthly firm service level values if applicable Select maximum number of events DR can be used and number of run hours Select the protocol that should be applied. This is used for determination of whether the LMR performed if called on during an EEA level 2 or higher. If other Public Page 8-15 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Resource Operator Contact Name (24 x7) Resource Operator Contact Phone Number (24 x7) Resource Operator Contact E-mail (24 x 7) Have you notified your LBA? Is a deployment plan in place with the LBA? Primary Contact Name (24 x7) Primary Contact Phone (24x7) Comments OPS-12 selected, please describe in box. Enter who to contact for deployment of DR. The contact should be available 24 x 7 for commitment by MISO or LBA. Enter phone number for 24 x 7 operator. Enter e-mail address for 24 x 7 operator. Indicate if you have contacted your LBA of this LMR located in their area Indicate if you have a deployment plan in place with the LBA where the resource is located? Enter name of person who should be contacted with questions on this registration. Enter phone number of person who should be contacted with questions on this registration. Submit any comments for this registration Public Page 8-16 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 OPS-12 Public Page 8-17 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Appendix E - BTMG registration Behind the Meter Generation (BTMG) Registration Requirements Explanation Plan Year Select the Planning Year you are registering your btmg. BTMG Name Enter Name of the BTMG. Description Enter type of resources and additional names and sizes if registering more than one unit. Registering Asset Owner Enter the name of the entity that owns or has rights to this asset. Local Resource Zone Select the Local Resource Zone where this btmg is located Local Balancing Area (LBA) Select the LBA where this BTMG asset is located. Load Zone CPNode Enter the CPNode where the BTMG asset is located. GADS Generator/ Intermittent Check box if the BTMG is an Intermittent Resource Resource GADS Generator Select the name of the GADS Generator(s) Accreditation Attach supporting documentation NERC Reporting Provide 24 monthly MW levels associated with the installed capacity of the BTMG each month. Monthly values shall be provided for the first two years from the Effective Start Date. Plan Year Interruptions and Run Time City (where the LMR is located) County (where the LMR is located) State (where the LMR is located) EDR? Emergency Demand Resource M&V protocol to be applied to this BTMG OPS-12 Provide 16 seasonal (Summer and Winter) MW levels associated with the installed capacity of the BTMG for each season. Seasonal values shall be provided beyond the 2 year monthly window. Select maximum number of events BTMG can be used and number of run hours Enter the city where the BTMG is located. Enter the county where the BTMG is located. Enter the state where the BTMG is located. Check box if BTMG registered as an EDR Select the registered name of the EDR. Select the protocol that should be applied. This is used for determination of whether the LMR performed if called on during an EEA level 2 or higher. If other selected, please describe in box. Public Page 8-18 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Start up notification time details (in hours) Do you hold all permits in place necessary to operate this resource? Do you hold all rights in place necessary to operate this resource? Have you notified your LBA? Is a deployment plan in place with the LBA? Resource Operator Contact Name (24 x7) Resource Operator Contact Phone Number (24 x7) Resource Operator Contact E-mail (24 x 7) Primary Contact Name (24 x7) Primary Contact Phone (24x7) Comments OPS-12 Enter the notification time required to start this BTMG. Needs to be less than 12 hours. Needs to be available 24 hours/Everyday (From 0000 to 2300 or from 0000 to 0000 acceptable) Indicate if all permits are in place in order for this resource to operate. Indicate if all rights are in place in order to operate this resource. Indicate if you have contacted your LBA of this LMR located in their area Indicate if you have a deployment plan in place with the LBA where the resource is located? Enter who to contact for deployment of DRBTMG. The contact should be available 24 x 7 for commitment by MISO or LBA. Enter phone number for 24 x 7 operator. Enter e-mail address for 24 x 7 operator . Enter name of person who should be contacted with questions on this registration. Enter phone number of person who should be contacted with questions on this registration. Submit any comments for this registration Public Page 8-19 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Appendix F – External Resources External Resources Registration Requirements Plan Year EXTERNAL RESOURCE Name Description Registering Asset Owner Local Resource Zone Local Balancing Area (LBA) Sink Load Zone CPNode Direct Ownership or PPA Direct Ownership GADS Generator IDC Name GADS registered capacity increased Unit Type Fuel Type Description Unit Size External Balance Authority where Resource(s) are located Interface CPNode NERC Regional Entity Description Use Limited Qualification Firm transmission to MISO border OPS-12 Explanation Select the Planning Year you are registering your External Resource. Enter Name of the EXTERNAL RESOURCE. Enter type of resources and additional names and sizes if registering more than one unit. Enter the name of the entity that owns or has rights to this asset. Select the Local Resource Zone where this External Resource is located Select the LBA where this EXTERNAL RESOURCE asset is located. Enter the CPNode where the EXTERNAL RESOURCE asset is located. Indicate if the External Resource is Directly Owned or PPA Enter MW value the Market Participant can register Select name of GADS Generator and input percentage if PPA otherwise select name of GADS generator Indicate the IDC name used for entering outages via the SDX. List separate IDC name for each unit being registered. Indicate if this resource needs to have its capacity increased by PRM and XEFORd Select Unit Type Select Fuel Type Provide Description of Unit Type and Fuel Type Select Unit Size Enter Balancing Authority where Resource(s) are located Select Interface CPNode Select NERC Regional Entity Provide description of NERC Regional Entity Indicate if this Resource meets the Use Limited Qualification Input effective date and OASIS reservation number and select Transmission Provider Public Page 8-20 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Firm transmission within MISO Have you notified the host BA? Is this External Resource only be used as a Capacity Resource in MISO? Is this External Resource available the entire Planning Year? Have all other requirements been met? Resource Operator Contact Name (24 x7) Resource Operator Contact Phone Number (24 x7) Resource Operator Contact E-mail (24 x 7) Primary Contact Name (24 x7) Primary Contact Phone (24x7) Comments OPS-12 Input effective date, OASIS and eDNR number Indicate if you have contacted your host BA of this registration. Indicate if you have a certified that this External Resource is only being used as a Capacity Resource for MISO. Indicate if this External Resource is available for the entire Planning Year. Indicate if all other requirements have been met. Enter who to contact for deployment of External Resource. The contact should be available 24 x 7 for commitment by MISO or LBA. Enter phone number for 24 x 7 operator. Enter e-mail address for 24 x 7 operator . Enter name of person who should be contacted with questions on this registration. Enter phone number of person who should be contacted with questions on this registration. Submit any comments for this registration Public Page 8-21 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Appendix H – Unforced Capacity (UCAP) Calculations for Planning Resources The following sets of equations establish how the unforced capacity values (NRIS UCAP and ERIS UCAP) are determined for Planning Resources to account for resource performance and availability. H.1 Planning Resource UCAP calculation for a Generation Resource, a Demand Response Resource backed by a generator, or a Behind-the-Meter Generator, with a Point of Interconnection on MISO’s Transmission System The unforced capacity calculation is based on its type and volume of interconnection service, GVTC, and forced outage rate (XEFORd). The following steps are used to calculate NRIS UCAP and ERIS UCAP for each Planning Resource. H.1.1 Planning Year UCAP Calculation The following steps are used to calculate NRIS UCAP and ERIS UCAP for each Planning Resource. The first step is to determine the total installed capacity that the Planning Resource can reliably provide, which is the Total Interconnection Installed Capacity (ICAP). It is equal to the lesser of its GVTC, or its total volume of Interconnection Service (Network Resource and Energy Resource Interconnection Service) granted either through MISO’s Generation Interconnection Procedures or through a market transition deliverability test. The equation is shown below. OPS-12 Public Page 8-22 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 The next step is to convert the resultant Total Interconnection ICAP value to unforced capacity value, Total Interconnection UCAP, by applying its forced outage rate (XEFORd). A forced outage rate class average is used if the Planning Resource has a GVTC < 10 MW and has not submitted generator availability data, or does not have sufficient generator availability data to calculate a Planning Resource specific forced outage rate. A Planning Resource has sufficient generator availability data when it has a minimum of 12 months of generator availability data between September 1st and August 31st for the previous 3 years. The applicable class average for a Planning Resource is based on its fuel type and unit size. The final step is to allocate the Planning Resource’s Total Interconnection UCAP based upon its type of Interconnection Service. To the extent the Planning Resource has Network Resource Interconnection Service (NRIS) or was determined to be aggregate deliverable through the market transition deliverability test then that quantity will be allocated first to calculate the NRIS UCAP. The remaining Total Interconnection UCAP will then be allocated to ERIS. . If the Planning Resource has provisional interconnection service then the Planning Resource will receive zero (0) interconnection service and therefore the calculated UCAP will be zero (0). NRIS UCAP , , ERIS UCAP 0, , OPS-12 Public Page 8-23 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 The NRIS UCAP and ERIS UCAP represent the capacity in MWs that is eligible to be converted into Zonal Resource Credits. H.2 UCAP calculation for an External Resource that qualified as a Capacity Resource The External Resource Capacity Resource unforced capacity calculation is based on its GVTC and forced outage rate (XEFORd). The ERIS UCAP is calculated by applying its XEFORd to its GVTC. 1 A forced outage rate class average is used if the Capacity Resource has a GVTC < 10 MW and has not submitted generator availability data, or does not have sufficient generator availability data to calculate a Planning Resource specific forced outage rate. A Planning Resource has sufficient generator availability data when it has a minimum of 12 months of generator availability data between September 1st and August 31st for the previous 3 years. The applicable class average for a Planning Resource is based on its fuel type and unit size. The ERIS UCAP represents the capacity in MWs that are eligible to be converted into Zonal Resource Credits. H.3 Planning Resource UCAP calculation for a Generation Resource, a Demand Response Resource backed by a generator, or a Behind-the-Meter Generator, which does not have a Point of Interconnection on MISO’s Transmission System The unforced capacity calculation is based on its GVTC and forced outage rate (XEFORd) if it does not have a Point of Interconnection to MISO’s Transmission System. The ERIS UCAP is calculated by applying its XEFORd to its GVTC. 1 A forced outage rate class average is used if the Load Modifying Resource (BTMG) has a GVTC < 10 MW and has not submitted generator availability data, or does not have sufficient OPS-12 Public Page 8-24 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 generator availability data to calculate a Planning Resource specific forced outage rate. A Planning Resource has sufficient generator availability data when it has a minimum of 12 months of generator availability data between September 1st and August 31st for the previous 3 years. The applicable class average for a Planning Resource is based on its fuel type and unit size. The ERIS UCAP represents the capacity in MWs that are eligible to be converted into Zonal Resource Credits. H.4 UCAP calculation for a Planning Resource that is classified as Intermittent Generation and Dispatchable Intermittent Resources The unforced capacity is determined based on past historical performance and availability data for non-wind resources and through an effective load carrying capability study at 80% confidence level performed by MISO for Planning Resources fueled by wind. The unforced capacity calculation also considers the type and volume of interconnection service for a Planning Resource that has a Point of Interconnection to MISO’s Transmission System. H.4.1 Intermittent Generation and Dispatchable Intermittent Resources with a Point of Interconnection on MISO’s Transmission System The following sets of equation establish how unforced capacity values (NRIS UCAP and ERIS UCAP) are determined for Intermittent Generation and Dispatchable Intermittent Resources that has a Point of Interconnection on MISO’s Transmission System to account for resource performance and availability. H.4.1.1 Intermittent Generation and Dispatchable Intermittent Resources Fueled by Wind MISO sets the GVTC to either the Pmax submitted through the Market Registration process if the Intermittent Generation and Dispatchable Intermittent Resources are registered in the Commercial Model or the registered maximum in its BTMG registration in the Module E Capacity Tracking Tool. OPS-12 Public Page 8-25 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 H.4.1.1.1 Planning Year UCAP Calculation for Wind Farms MISO calculates a wind farm specific wind capacity credit, by CPnode, for each Planning Resource that is fueled by wind. The wind capacity credit is determined by performing an Effective Load Carry Capability study on an annual basis and using wind farm specific past metered data, reference section 4.5 of the BPM for Resource Adequacy. The first step is to determine the total installed capacity that the Planning Resource can reliably provide, which is the Total Interconnection Installed Capacity (ICAP). It is equal to the lesser of its GVTC, or its total volume of Interconnection Service (Network Resource and Energy Resource Interconnection Service) granted either through MISO’s Generation Interconnection Procedures or through a market transition deliverability test. , , The next step is to convert the resultant Total Interconnection ICAP value to an unforced capacity value, Total Interconnection UCAP, by applying its CPnode specific wind capacity credit. The final step is to allocate the Total Interconnection UCAP based upon its type of Interconnection Service. To the extent the Planning Resource has Network Resource Interconnection Service (NRIS) or was determined to be aggregate deliverable through the market transition deliverability test then that quantity will be allocated first to NRIS UCAP. The remaining Total Interconnection UCAP will then be allocated to ERIS. If the Planning Resource has provisional interconnections service then the Planning Resource OPS-12 Public Page 8-26 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 will receive zero (0) interconnection service and therefore the calculated UCAP will be zero (0). NRIS UCAP , , 0, , ERIS UCAP H.4.1.2 Non-wind Intermittent Generation and Dispatchable Intermittent Resources The GVTC for Intermittent Generation and Dispatchable Intermittent Resources with a fuel source other than wind is calculated in section 4.2.2 of this BPM. The first step is to determine the total installed capacity that the Planning Resource can reliably provide, which is the Total Interconnection Installed Capacity (ICAP). It is equal to the lesser of its GVTC, or its total volume of Interconnection Service (Network Resource and Energy Resource Interconnection Service) granted either through MISO’s Generation Interconnection Procedures or through a market transition deliverability test. , , The final step is to allocate the Total Interconnection UCAP based upon its type of Interconnection Service. To the extent the Planning Resource has Network Resource Interconnection Service (NRIS) or was determined to be aggregate deliverable through the market transition deliverability test then that quantity will be allocated first to the NRIS UCAP. The remaining Total Interconnection UCAP will then be allocated to ERIS. If the Planning Resource has provisional interconnections service then the Planning Resource will receive zero (0) interconnection service and therefore the calculated UCAP will be zero (0). OPS-12 Public Page 8-27 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 , , 0, , H.4.2 Intermittent Generation and Dispatchable Intermittent Resources that does not have Point of Interconnection on MISO’s Transmission System The following equations apply to Intermittent Generation and Dispatchable Intermittent Resources that do not have a Point of Interconnection on MISO’s Transmission System. The ERIS UCAP represents the capacity in MWs that are eligible to be converted into Zonal Resource Credits. H.4.2.1 Intermittent Generation and Dispatchable Intermittent Resources Fueled by Wind MISO sets the GVTC to either the Pmax submitted through the Market Registration process if the Intermittent Generation and Dispatchable Intermittent Resources are registered in the Commercial Model or the registered maximum in its BTMG registration in the Module E Capacity Tracking Tool. H.4.2.1.1 Planning Year UCAP Calculation MISO calculates a wind farm specific wind capacity credit for each Planning Resource that is fueled by wind. The wind capacity credit is determined by performing an Effective Load Carry Capability study on an annual basis and using wind farm specific past metered data, reference section 4.5 of the BPM for Resource Adequacy. OPS-12 Public Page 8-28 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 H.4.2.2 Non-wind Intermittent Generation and Dispatchable Intermittent Resources The GVTC for Intermittent Generation and Dispatchable Intermittent Resources with a fuel source other than wind is calculated in section 4.2.2 of this BPM. ERIS OPS-12 Public Page 8-29 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Appendix I - XEFORd Calculation To help better understand how the XEFORd value is determined a description of the EFORd has been provided below: The equivalent forced outage rate demand calculation is based on the equation defined in the IEEE Standard No. 762 “Definitions for Use in Reporting Electric Generating Unit Reliability, Availability and Productivity.” This equation is shown below. EFOR d FOH d EFDH d FOH d SH x 100 % where: FOHd = ff x FOH EFDHd = (EFDH – EFDHRS) if reserve shutdown events reported, or = (fp x EFDH) if no reserve shutdown events reported. Please note that the IEEE Standard No. 762 and NERC definitions for EFDH differ slightly from the way MISO’s PowerGADS tool calculates EFDH. These differences can be seen below. IEEE and NERC’s definition for EFDH: (Derated Hours * Size of Reduction)/Net Max Capacity PowerGADS definition for EFDH: (Derated Hours * Size of Reduction)/Net Dependable Capacity The Size of Reduction is equal to the Net Dependable Capacity minus the Net Available Capacity OPS-12 Public Page 8-30 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 ff = full forced outage factor = (1/r + 1/ T)/(1/r + 1/T +1/D) r = average forced outage duration = (FOH)/(# of FO occurrences) D = average demand time = (SH + Synch Hours)/(# of unit actual starts) T = average reserve shutdown time = (RSH)/(# of unit attempted starts) FOH = full forced outage hours SH = service hours Synch Hours = synchronous hours RSH = reserve shutdown hours EFDH = equivalent forced de-rated hours EFDHRS = equivalent forced de-rated hours during reserve shutdowns fp = partial forced outage factor = ((SH + Synch Hours)/AH) AH = available hours Note: Special cases are evaluated in the following order: If reserve hours < 1, then ff =1 Else if (SH + Synch hours) = 0, then ff = 1 Else if (1/r + 1/T + 1/D) = 0, then ff = 0 Else if # of FO occurrences = 0 or FOH = 0, then 1/r = 0 Else if RSH = 0 or # of unit attempted starts = 0, then 1/T = 0 OPS-12 Public Page 8-31 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Else if # of unit actual starts = 0 or (SH + Synch Hours) = 0, then 1/D = 0 Else if (SH+RSH+Synch Hours) = 0, then fp = 0 Else if ((SH + Synch Hours) + (ff x FOH)) = 0, then EFORd = 0 Example Raw Data Actual Attempted FO Unit Capacity(MW) SH RSH AH Starts Starts EFDH FOH events 1 55 4,856 2,063 6,918 34 34 146.99 773 12 2 75 4,556 1,963 6,519 31 31 110.51 407 5 3 120 3,942 3,694 7,635 36 36 19.92 504 11 4 153 6,460 516 6,978 17 18 131.03 340 14 5 180 6,904 62 6,968 14 16 35.81 138 12 Totals 583 26,718 8,298 35,018 132 135 444.26 2,162 54 Calculated Intermediate Values Unit 1/r 1/T 1/D ff ff * FOH = FOHd fp fp * EFDH = EFDHd EFORd 1 0.0155 0.0165 0.0070 0.8205 634.25 0.7019 103.18 13.43% 2 0.0123 0.0158 0.0068 0.8049 327.61 0.6989 77.23 8.29% 3 0.0218 0.0097 0.0091 0.7756 390.92 0.5163 10.28 9.26% 4 0.0412 0.0329 0.0026 0.9657 328.34 0.9258 121.30 6.62% 5 0.0870 0.2258 0.0020 0.9936 137.11 0.9908 35.48 2.45% 346.18 8.01% Totals 1,818.23 OPS-12 Public Page 8-32 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 OPS-12 Public Page 8-33 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 EFORd Calculation for Unit 1: Synch Hours = 0 FOH 773 64.41667 # of FO 12 RSH 2,063 60.67647 T average reserve shutdown t ime # of Attempted Starts 34 SH 4,856 142.82353 D average demand time # of Actual Starts 34 1 1 0.0155 0.0165 0.8205 f f full forced outage factor r T 1 1 1 0.0155 0.0165 0.0070 r T D SH 4,856 0.7019 f p partial forced outage factor AH 6,918 r average forced outage duration EFOR d FOH d EFDH d 634.25 103.18 x 100% 13.43% x 100% 4,856 634.25 SH FOH d Additional Note: SH, RSH and Synch Hours are reported by the users in the Performance data. The rest of the statistics are calculated by PowerGADS based on Event data submitted by the users. EFORd for each unit is presented in the Generator Outage Rate Program (GORP) report. The statistics used in calculating EFORd can be found in the Statistics Report and the Performance Report. The EFORd calculation is applied differently for unique instances such as existing and new units. This calculation is based on the historical data from MISO’s GADS database. Each unit’s EFORd value that is used for the Planning Year will be based on either a class average value for that particular unit’s size and type or the unit’s actual data. A class average value will not be blended with a unit’s actual data to determine a 36 month EFORd or XEFORd. OPS-12 Public Page 8-34 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Existing Units or Units with 12 or more consecutive months of actual data: The EFORd of a unit in service twelve or more full calendar months prior to the calculation month will be based on the number of consecutive months that that unit has data for up to 36 months. Eventually, each unit will have a 36 month EFORd based on actual data. Example: If a unit has 12 consecutive months of actual data only, then it is assigned an EFORd value based on those 12 months. If a unit has 27 consecutive months of actual data only, then it is assigned an EFORd value based on those 27 months. If a unit has 36 consecutive months of actual data only, then it is assigned an EFORd value based on those 36 months. New Units or Units with less than 12 consecutive months of actual data: The EFORd of a unit in service less than twelve full calendar months shall be determined by the class average rate for units within the same range of capability and type. A unit will use the class average value until 12 consecutive months of data is obtained and a new Planning Year has occurred. Units with Low Service Hours BPM Language Units with an average of 80 service hours or less per year can have their service hours adjusted if the unit has at least 12 consecutive months of GADS data. The adjusted service hours will be based on 240 service hours (80 service hours x 3 years) or a fraction of 240 if less than 36 consecutive months of GADS data. This adjustment will be performed automatically by MISO staff. The calculation for the adjustment is as follows: Qualification: SH ≤ (MO/36 * 240) SH = Service Hours (actual) MO = consecutive Months in operation Adjusted Service Hours, if qualified: OPS-12 Public Page 8-35 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 External Resources: Market Participants are responsible for making sure that GADS data is submitted from the External Resources that they are seeking qualification as ZRCs. The Market Participant can submit this data to MISO’s GADS tool for the external resource or they can have the external resource submit the data. If an external resource is going to submit the GADS data, then they must receive access to the MISO Market Portal through their Local Security Administrator. If an External Resource does not have a Local Security Administrator then it is the Market Participant’s responsibility to receive and submit this data for the External Resource. OPS-12 Public Page 8-36 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Behind The Meter Generation: For the initial Planning Year, all BTMG units will receive a class average EFORd value based on the unit type and size, unless GADS data that the MP for the BTMG submits to MISO the Those units less Those than value. 10 MW less Those that thando units 10not MW less Midwest ISO demonstrates thetheMISOthe demonstrates a MISOMISO higher average ademonstrates higher EFOR average a higher EFOR average EFOR d value. d value. dunits submit than that do 10GADS not MWsubmit that data doGADS will notreceive submit data will the GADS receive class data average. the willclass receive For average. the theinitial class ForPlanning average. the initial Year, For Planning the theinitial class Year, average Planning the classthe Year, average class theaverage EFOR class daverage classd of average EFOR orEFOR actual or EFOR actual EFOR the BTMG thewill BTMG beactual used. will be EFOR The used. Unforced the Unforced BTMG Capacity dthe d of d or d ofThe Capacity calculation will be used. calculation is The shown Unforced in is shown section Capacity in7.7.2. section calculation Section 7.7.2.4.4.1 Section is shown Registration 4.4.1 in section Registration of Load 7.7.2. Modifying ofSection Load Modifying 4.4.1 Resources Resources and Registration sectionand 4.5.4 of Load section Annual Modifying 4.5.4 Performance Annual Resources Performance Testing and section for LMRs Testing 4.5.4 provides forAnnual LMRs additional Performance providesdetails additional Testing on thefor registration and the qualification athe BTMG. details LMRs provides on the registration additional and details theof on qualification registration of a BTMG. and theAqualification BTMG that seeks of a BTMG. to qualify A as an BTMG LMRthat beyond seeksthe to initial qualifyPlanning as an LMR Yearbeyond is required the initial to perform Planning a generation Year is required capability to test following perform athe generation applicable capability Regional test Entity following standards the applicable and submit Regional the results Entity viastandards GADs, before and March submit 1the of results the Planning via GADs, Year.before March 1 of the Planning Year. Pooled Class Average Rates: The class average values are only used in place of actual data when such data are not available either due to the unit being new, or without adequate historical performance or operating statistics. These values are calculated from MISO’s GADS database based on unit size and type. MISO’s EFORd classes will be the same as defined by NERC’s Generating Unit Statistical Brochure. An example is shown below: OPS-12 Public Page 8-37 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Appendix J – GVTC Testing Requirements All Generation Resources, External Resources, Demand Response Resources backed by behind-the-meter generation and BTMG that intend to qualify as or being used as a Planning Resources are required to perform a real power test or provide past operational data that meets these requirements to determine its GVTC and submits its GVTC data to MISO’s PowerGADS. If a Planning Resource fails to perform a real power test during the testing period and report the test information to MISO’s PowerGADS by the reporting deadline, it will result in the Planning Resource not qualifying as a Planning Resource and will receive zero (0) UCAP MWs for the upcoming Planning Year. J.1 Generation Verification Test Capacity (GVTC) The maximum Energy output (MW) that a Generation Resource, External Resource, Demand Response Resource backed by behind the meter generation, or Behind the Meter Generation (BTMG) can sustain over the specified period of time, if there are no equipment, operating, or regulatory restrictions, minus any Capacity utilized for the units station service power. J.2 When to Perform and Submit a Generation Verification Test Capacity Generation Resources, External Resources, Demand Response Resources backed by behind the meter generation, or Behind the Meter Generation that qualified as Planning Resources for the current Planning Year shall submit their GVTC no later than October 31st in order to qualify as a Planning Resource for the upcoming Planning Year. The real power test shall be performed or past operational data shall be between September 1st and August 31st prior to the upcoming Planning Year OPS-12 Public Page 8-38 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 A real power test is required to demonstrate a modification that increases the rated capacity of a unit, and then submit the revised GVTC. A real power test is required when returning from a “mothballed” state, and then submit the GVTC A real power test is required when any existing or new unit returns to MISO after an absence (including but not limited to, catastrophic events, or not qualified as a Planning Resource under Module E) or being qualified as a Planning Resource for the first time o The GVTC for a new BTMG is due before a Market Participant registers its new BTMG in the MECT, at least 60 days prior to the first Planning Month that the BTMG is effective in the Module Capacity Tracking Tool OPS-12 Public Page 8-39 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 J.3 Adjustment to establish the GVTC The GVTC shall be temperature corrected to the average temperature of the date and times of MISO’s coincident Summer peak, measured at or near the generator’s location, for the last 5 years. MISO publishes the date and time of the past 5 annual coincident Summer Peaks. When local weather records are not available at the plant site the values shall be determined from the best data available (i.e. local weather service, local airports, river authority, etc.) The adjustments required to establish the GVTC of a unit include, as appropriate for each electric generating technology, ambient temperature, humidity, condensing water OPS-12 Public Page 8-40 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 temperature and availability, fuels, steam heating loads, reservoir level, nuclear fuel management programs and scheduled reservoir discharge. J.4 Generation Verification Test Capacity During a Derate A Market Participant that performs a GVTC when a unit has a documented derate in MISO PowerGADS can request MISO to adjust its GVTC if the documented derate in MISO GADs lasted a minimum of 90 consecutive days prior to the test data and generator availability data has been reported to MISO prior to any adjustments to the GVTC. The Market Participant shall contact MISO’s Resource Adequacy Department for a review of its request. J.4.1 Interconnection Service Limitations All Planning Resources GVTC are subject to Interconnection Service limitations to the bus to which the facility is currently or about to be connected to as verified by the Transmission Service Planning Department of MISO. J.5 GVTC Real Power Test Requirements J.5.1 Thermal Steam and Nuclear The GVTC capability will be validated for each unit type for a period of not less than two (2) continuous hours and will be the average of the two (2) hours. Generating units GVTC as affected by the turbine exhaust pressure will be corrected to the past five years (or if a generating unit has not been in operation for five years or more, then as many years as the unit has been in operation) average daily maximum circulating water temperature measured at the date and time of MISO’s Summer Peak. The GVTC for new OPS-12 Public Page 8-41 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 generating units will be corrected based on estimated average daily maximum circulating water temperature measured at the date and time of MISO’s Summer Peak. Steam conditions will correspond to operating standards established by the generator owner for the unit or plant. Capability of nuclear units will be determined taking into consideration the fuel management program and any restrictions imposed by regulatory agencies. J.5.2 Combined-cycle units The gross capability and net continuous GVTC will be validated for a period of not less than two (2) continuous hours and will be the average of the two (2) hours that result in the highest GVTC. Generating unit GVTC as affected by the turbine exhaust pressure will be corrected to the past five years (or if a generating unit has not been in operation for five years or more, then as many years as the unit has been in operation) average daily maximum circulating water temperature measured at the date and time of MISO’s Summer Peak, and the ambient air temperature and humidity conditions experienced at the unit location at the time of MISO’s Summer Peak. The GVTC for new generating units will be corrected based on estimated average daily maximum circulating water temperature measured at the date and time of MISO’s Summer Peak given humidity conditions experienced at the unit location at the time of MISO’s Summer Peak. GVTC of a unit shall be reported for the unit as a whole, as well as for the individual combustion turbine(s) and the steam turbine(s). Steam conditions will correspond to the operating standard established by the Generator Owner. The unit shall be operated with the regularly available type and quality of fuel. OPS-12 Public Page 8-42 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 The determination of the GVTC of a combined-cycle unit will depend on the structure of the complete unit and its components. The steam turbine and combustion turbine(s) shall adhere to the guidelines in this reporting manual. In the case of thermally dependent components the determination of the GVTC shall require the operation of both combustion turbine(s) and steam components simultaneously. The output of the components can be netted to determine the combined-cycle unit GVTC. J.5.3 Combustion Turbine, Internal Combustion, and Diesel Units The gross capability and continuous GVTC will be validated for a period of not less than one (1) hour. Ambient temperature and humidity conditions to be used for adjusting the measured test output shall be the average for the past five years of the maximum temperature and humidity occurring the day of MISO’s system summer maximum peak. Where inlet cooling is used to reduce turbine inlet air temperature; the temperature at the discharge of the Inlet coolers shall be the basis for ambient temperature adjustment. Unit shall be operated with regularly available type and quality of fuel. For a facility that consists of multiple units, auxiliary load for a shared auxiliary power system shall be allocated to the individual units to compute unit net capability. J.5.4 Hydroelectric Units – Pumped storage and Reservoir The gross capability and continuous GVTC will be validated for a period of not less than one (1) hour. The GVTC established for hydroelectric plants shall recognize the head available giving proper consideration to environmental, operational, and regulatory restrictions and ambient conditions such as forecasted reservoir levels or water flow conditions. The test capability shall be corrected to historic median head conditions as specified below. OPS-12 Public Page 8-43 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 The historic median head shall be determined as the median of all head measurements for hours ending 1500-1700 EST for all days of the Summer (June, July, August) from the most recent five (5) years up to the most recent fifteen (15) years for Reservoir Hydro and Pumped Storage. If 15 years of historic data is not available for this period when the 15 year time period is chosen, or is no longer relevant due to environmental, operational, regulatory or other restrictions, all available relevant data shall be used and accumulated until the 15 year requirement is met. Once the number of years and methodology is chosen and submitted as GVTC requirements, the same number of years must be submitted in future GVTC data collection. Each hydro unit shall be verified individually. The entire hydro plant shall be verified if the sum of individual unit capabilities is greater than the total plant capability. Reporting The following information shall be reported to MISO’s GADS as appropriate. Please consult MISO’s Net Capability Verification Test User Manual for more details with respect to the fields shown below. CARD Utility Unit Year Period Test Index REVISIONCODE Corrected Net Claimed Installed Difference Unit Type Test Start Date Test End Date Gross MW Station Service OPS-12 Must be "90" Required Required Required Must be "S" for Summer Must be a "1" Must be "0" for initial upload, "R" to Revise, or "D" to Delete Leave Blank Leave Blank Leave Blank Optional. If entered should be CT, ST, DS, HD, NU, CC, FB or PS Required Required Required Required Public Page 8-44 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Process Load Served Net Test Capability Reactive Generation MVAR Total Power MVA Power Factor Dry Air Temperature Observed Dry Air Temperature Rated Air Temperature Correction Relative Humidity Observed Relative Humidity Rated Relative Humidity Correction Cooling Water Temperature Observed Cooling Water Temperature Rated Cooling Water Temperature Correction STANDARD Required Required Optional Leave Blank Leave Blank Required for certain unit types Required for certain unit types Required Required for certain unit types Required for certain unit types Required Required for certain unit types Required for certain unit types Required Must be "MISO" Reporting is accomplished through MISO’s PowerGADS reporting system as described in MISO’s Net Capability Verification Test User Manual, which is located on MISO’s website under Documents→ Resource Adequacy→ Documents. OPS-12 Public Page 8-45 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Appendix K – Resource Adequacy Timeline Month Day Sep 1st Oct 31st Nov 1st Nov 1st Nov 1st Dec 1st Dec 15th Jan 1st Bus. day Jan 15th Feb 1st Feb 1st Feb 16th Mar 1st Mar 1st Mar 1st OPS-12 Process 2013‐14 PY Annual Cost of New Entry for 7 LRZs filing due to FERC Generation Verification Test Capacity/Generator Availability Data due Coincident Peak Demand forecast by LSE/EDC , the 24 monthly and 16 seasonal peak demand and energy forecast values by LSE due Loss of Load Expectation study results published by MISO (Publish PRM, Develop LRZs, Determine CIL and CEL, Establish LRR) Evidence for new GMA/Zonal Deliverability Charge hedges due Unforced Capacity values are published by MISO Peak Load Contribution submissions by EDC due (EDC will send the details of the PLCs to both the respective LSEs and the MISO for their review) Transmission losses by Local Balancing Authority are posted by MISO LSEs submit the Retail Choice PLC in the MECT 9/3/2012 Loss of Load Expectation study begins for next Planning Year Existing Load Modifying Resource/Energy Efficiency/ External Resource registrations due for prompt Planning Year Submit data for facility ZRC reference levels to IMM due 45 days prior to the close of the PRA IMM posts initial ZRC reference level generic data 30 days prior to the close of the PRA New Load Modifying Resource/Energy Efficiency Resource/ External Registrations due for prompt Planning Year Generator Verification Test Capacity/Generator Availability Data for new resources or resources with increased capacity prompt Planning Year Public 10/31/2012 Responsible entity MISO 11/1/2012 Resource Owner LSE, EDC 11/1/2012 MISO 11/1/2012 LSE 12/1/2012 12/15/2012 MISO EDCS in Retail Choice 1/2/2013 MISO 1/15/2013 2/1/2013 LSEs in Retail Choice MISO 2/1/2013 LMR Owner 2/16/2013 Gen. Owner 3/1/2013 IMM* 3/1/2013 LMR Owner 3/1/2013 LMR Owner Page 8-46 APSC FILED Time: 8/2/2013 11:49:20 AM: Recvd 8/2/2013 11:37:54 AM: Docket 13-028-U-Doc. 240 Resource Adequacy Business Practice Manual BPM-011-r11 effective date: OCT-01-2012 Month Day Process 2013‐14 PY Responsible entity MISO to complete its Coincident Peak Demand forecast review process Grandmother Agreement and Zonal Deliverability Charge hedge information posted by MISO Fixed Resource Adequacy Plan due by LSE 3/1/2013 MISO 3/1/2013 MISO 3/11/2013 LSE 3/15/2013 MISO(LSE) 3/25/2013 IMM# 3/27/2013 MISO 4/1/2013 MISO/IMM* 4/5/2013 MISO 4/8/2013 MISO 4/15/2013 MISO 4/22/2013 MISO 4/24/2013 MISO 6/1/2013 6/1/2013 All All Mar 1st Mar 1st Mar 7th Bus. day Mar 15th Fixed Resource Adequacy Plan review completed by MISO (The LSE will have until the PRA offer window opens to remedy any deficiencies in their FRAP.). Mar 25th Provide unit specific threshold data 5 days prior to the close of the Auction Mar Last 3 Bus. Planning Resource Auction offer window is days opened Apr 1st 5 Bus. Iterations of auction runs with the adjusted CILs Days and CELs may be required to ensure that a network loading is not violated. Additionally, MISO will work with the IMM to evaluate potential withholding . Apr 5th Bus. Planning Resource Auction results posted day Apr 6th Bus. Assess the Capacity Deficiency Charge Day Apr 11th Bus. MISO sends out the Capacity Deficiency Charge day Apr 11th Bus. Capacity Deficiency Charge payment due days + 7 Apr 11th Bus. Capacity Deficiency Charge payments made to days + 7 + MPs 2 Bus. days Jun 1st New Planning Year starts Jun 1st Daily settlements for the new planning year starts OPS-12 Public Page 8-47
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